diff --git a/raw/filings/0000794172/2014/0001193125-14-428676/filing.txt b/raw/filings/0000794172/2014/0001193125-14-428676/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..7f31ce8ce693c6102f610bc49f68c2098eacfaf9 --- /dev/null +++ b/raw/filings/0000794172/2014/0001193125-14-428676/filing.txt @@ -0,0 +1,3687 @@ +10-K +1 +d806176d10k.htm +ANNUAL REPORT +Annual Report +Table of Contents +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +FOR ANNUAL +AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +x +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2014. +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM +TO +Commission File No. 0-14902 +MERIDIAN +BIOSCIENCE, INC. +3471 River Hills Drive +Cincinnati, Ohio 45244 +IRS Employer ID No. 31-0888197 +Incorporated under the Laws of Ohio +Phone: (513) 271-3700 +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange of which registered +Common Shares, No Par Value +The NASDAQ Stock Market LLC +(NASDAQ Global Select Market) +Securities Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the +registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES x NO ¨ +If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or +15(d) of the Securities Exchange Act. YES ¨ NO x +Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act +of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web +site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such +files). YES x NO ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this Chapter) is not contained +herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form +10-K. YES ¨ NO x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See +definitions of “large accelerated filer” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +x +Accelerated filer +¨ +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule +12b-2). YES ¨ NO x +The aggregate market value of Common Shares held by non-affiliates as of March 31, 2014 was $887,064,755 based on a closing sale price of $21.79 per +share on March 31, 2014. As of October 31, 2014, 41,644,524 no par value Common Shares were issued and outstanding. +Documents +Incorporated by Reference +Portions of the Registrant’s Annual Report to Shareholders for the fiscal year ended September 30, 2014 furnished +to the Commission pursuant to Rule 14a-3(b) are incorporated by reference in Part II as specified and portions of the Registrant’s Proxy Statement to be filed with the Commission for its 2015 Annual +Shareholders’ Meeting are incorporated by reference in Part III as specified. +Table of Contents +MERIDIAN BIOSCIENCE, INC. +INDEX TO ANNUAL REPORT +ON FORM 10-K +Page +Part I +Item 1 +Business +5 +Item 1A +Risk Factors +16 +Item 1B +Unresolved Staff Comments +24 +Item 2 +Properties +24 +Item 3 +Legal Proceedings +25 +Item 4 +Mine Safety Disclosures +25 +Part II +Item 5 +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +26 +Item 6 +Selected Financial Data +26 +Item 7 +Management’s Discussion and Analysis of Financial Condition and Results of Operations +27 +Item 7A +Quantitative and Qualitative Disclosures about Market Risk +44 +Item 8 +Financial Statements and Supplementary Data +45 +Item 9 +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +73 +Item 9A +Controls and Procedures +73 +Item 9B +Other Information +73 +Part III +Item 10 +Directors, Executive Officers and Corporate Governance +74 +Item 11 +Executive Compensation +74 +Item 12 +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +74 +Item 13 +Certain Relationships and Related Transactions, and Director Independence +74 +Item 14 +Principal Accounting Fees and Services +74 +Item 15 +Exhibits and Financial Statement Schedules +75 +FORWARD LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements. The Private Securities Litigation Reform Act of 1995 provides a safe harbor from civil +litigation for forward-looking statements accompanied by meaningful cautionary statements. Except for historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as +amended, and Section 21E of the Securities Exchange Act of 1934, which may be identified by words such as “estimates”, “anticipates”, “projects”, “plans”, “seeks”, “may”, +“will”, “expects”, “intends”, “believes”, “should” and similar expressions or the negative versions thereof and which also may be identified by their context. All statements that address operating +performance or events or developments that Meridian expects or anticipates will occur in the future, including, but not limited to, statements relating to per share diluted earnings and revenue, are forward-looking statements. Such statements, +whether expressed or implied, are based upon current expectations of the Company and speak only as of the date made. Specifically, Meridian’s forward-looking statements are, and will be, based on management’s then-current views and +assumptions regarding future events and operating performance. Meridian assumes no obligation to publicly update or revise any forward-looking statements even if experience or future changes make it clear that any projected results expressed or +implied therein will not be realized. These statements are subject to various risks, uncertainties and other factors that could cause actual results to differ materially, including, without limitation, the following: Meridian’s continued growth +depends, in part, on its ability to introduce into the marketplace enhancements of existing products or new products that incorporate technological advances, meet customer requirements and respond to products developed by Meridian’s +competition, and its ability to effectively sell such products. While Meridian has introduced a number of internally developed products, there can be no assurance that it will be successful in the future in introducing such products on a timely +basis. Meridian relies on proprietary, patented and licensed technologies, and the Company’s ability to protect its intellectual property rights, as well as the potential for intellectual property litigation, would impact its results. Ongoing +consolidations of reference laboratories and formation of multi-hospital alliances may cause adverse changes to pricing and distribution. Recessionary pressures on the economy and the markets in which our customers operate, as well as adverse trends +in buying patterns from customers can change expected results. Costs and difficulties in complying with laws and regulations, including those administered by the United States Food and Drug Administration, can +Table of Contents +result in unanticipated expenses and delays and interruptions to the sale of new and existing products. The international scope of Meridian’s operations, including changes in the relative +strength or weakness of the U.S. dollar and general economic conditions in foreign countries, can impact results and make them difficult to predict. One of Meridian’s growth strategies is the acquisition of companies and product lines. There +can be no assurance that additional acquisitions will be consummated or that, if consummated, will be successful and the acquired businesses will be successfully integrated into Meridian’s operations. There may be risks that acquisitions may +disrupt operations and may pose potential difficulties in employee retention and there may be additional risks with respect to Meridian’s ability to recognize the benefits of acquisitions, including potential synergies and cost savings or the +failure of acquisitions to achieve their plans and objectives. Meridian cannot predict the possible impact of U.S. health care legislation enacted in 2010 – the Patient Protection and Affordable Care Act, as amended by the Health Care and +Education Reconciliation Act – and any modification or repeal of any of the provisions thereof, and any similar initiatives in other countries on its results of operations. Efforts to reduce the U.S. federal deficit, breaches of Meridian’s +information technology systems and natural disasters and other events could have a materially adverse effect on Meridian’s results of operations and revenues. In addition to the factors described in this paragraph, Part I, Item 1A Risk +Factors contains a list and description of uncertainties, risks and other matters that may affect the Company. +Table of Contents +PART I. +This Annual Report on Form 10-K includes forward-looking statements about our business and results of operations that are subject to risks and uncertainties. +See “Forward Looking Statements” above. Factors that could cause or contribute to such differences include those discussed in Item 1A. Risk Factors. In addition to the risk factors discussed herein, we are also subject to additional +risks and uncertainties not presently known to us or that we currently deem immaterial. If any of these risks and uncertainties develops into actual events, our business, financial condition or results of operations could be adversely affected. +Unless the context requires otherwise, references in this Annual Report on Form 10-K to “Meridian,” “we,” “us,” +“our,” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +In the discussion that follows, all dollars and +shares are in thousands (both tables and text), except per share data. +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in (i) the development, manufacture, sale and distribution of diagnostic +test kits, primarily for certain gastrointestinal, viral, respiratory and parasitic infectious diseases; (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch +reagents used by researchers and other diagnostic manufacturers; and (iii) the contract development and manufacture of proteins and other biologicals under cGMP conditions for use by biopharmaceutical and biotechnology companies engaged in +research for new drugs and vaccines. The Company was incorporated in Ohio in 1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on +Form 10-Q, Current Reports on Form 8-K and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or +furnished to the Securities and Exchange Commission (SEC). These reports may also be read and copied at the SEC’s public reference room at 100 F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these filings and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered +part of this Annual Report on Form 10-K. +Reportable Segments +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, and the sale and +distribution of diagnostic test kits in the U.S. and Canada (“North America”); Europe, Middle East and Africa (“EMEA”); and other countries outside of North America +- 5 - +Table of Contents +and EMEA (rest of the world, or “ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; +and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically and abroad, including a sales and business development location in Singapore. +Additionally, in order to further pursue revenue opportunities in Asia, and China in particular, our Life Science segment is in the process of opening a representative office in Beijing, China. The Life Science segment also includes the contract +development and manufacture of cGMP clinical grade proteins and other biologicals for use by biopharmaceutical and biotechnology companies engaged in research for new drugs and vaccines. Financial information for Meridian’s reportable segments +is included in Note 7 to the consolidated financial statements. +Diagnostics Segment +Overview of Products and Markets +Our primary +source of revenues continues to be diagnostic products, with our Diagnostics segment providing 75% of consolidated net revenues for fiscal 2014. Third-party revenues for this segment were $142,000, $145,000 and $130,000 for fiscal 2014, 2013 and +2012, respectively, reflecting a three-year compound annual growth rate of 6%. As of September 30, 2014, our Diagnostics segment had approximately 350 employees in seven countries. +Our diagnostic products provide accuracy, simplicity and speed; enable early diagnosis and treatment of common, acute medical conditions; and provide for +better patient outcomes at reduced costs. We target diagnostics for disease states that (i) are acute conditions where rapid diagnosis impacts patient outcomes; (ii) have opportunistic demographic and disease profiles; (iii) are +underserved by current diagnostic products; and (iv) have difficult sample handling requirements (stool, blood, urine and other body fluids). This approach has allowed us to establish significant market share in our target disease states. +Our diagnostic products span a broad menu of testing platforms and technologies, and also include transport media that store and preserve specimen samples +from patient collection to laboratory testing. Our testing platforms include: +• +Isothermal DNA Amplification ( illumi gene ® brand) – high sensitivity, molecular platform that +is suitable for virtually any size laboratory, whether centralized or decentralized; provides flexibility to process from 1 to 10 tests per run in generally under one hour; and requires no batching of samples. +• +Rapid Immunoassay (TRU ® , Immuno Card ® and +Immuno Card STAT! ® brands) – single-use immunoassays that can be used in point-of-care settings; these tests have fast turnaround times +(generally under 20 minutes); and can reduce expensive send-outs for hospitals and outpatient clinics. +- 6 - +Table of Contents +• +Enzyme-linked Immunoassay (Premier ® brand) – batch immunoassay platform that can process up to 96 tests per run; is highly +accurate and economical; and is adaptable to automation. +Our diagnostic products are used principally in the detection of infectious +diseases caused by various bacteria, viruses, parasites and pathogens. Our focus product families in Diagnostics are C. difficile (causative agent for antibiotic-associated diarrhea from a hospital-acquired infection), foodborne +(Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy)), and H. pylori (stomach ulcers). Revenues within our focus product families – C. difficile, foodborne and H. pylori – accounted for 61%, +62% and 62% of our Diagnostics segment’s third-party revenues during fiscal 2014, 2013 and 2012, respectively. These same product families accounted for 46%, 47% and 47% of consolidated net revenues in fiscal 2014, 2013 and 2012, +respectively. +Our product portfolio, over 140 diagnostic tests and transport media, extends beyond our focus families, reaching into +prenatal care (Group B Streptococcus ), respiratory (Group A Streptococcus, Bordetella pertussis , influenza and respiratory syncytial virus, among others), and immunocompromised patients (Cytomegalovirus), among other infectious disease +areas. During the next three to five years, we expect revenue growth from products operating on our illumi gene ® molecular testing platform (see below) that fall +outside of our focus families noted above. The primary markets and customers for our products are acute care hospitals, reference laboratories and outpatient clinics in over 60 countries around the world. +We continue to invest in new product development for our molecular testing platform, illumi gene . This platform now has five +commercialized tests (assays), with three additional tests expected to be available for sale in fiscal 2015: +1. +illumi gene ® C. difficile – commercialized in August 2010 +2. +illumi gene ® Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene ® Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene ® Mycoplasma ( M. pneumonia ; walking pneumonia) – commercialized in June 2013 +5. +illumi gene ® Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene ® Chlamydia trachomatis – expected fiscal 2015 (launch outside of U.S.) +7. +illumi gene ® Neisseria gonorrhea – expected fiscal 2015 (launch outside of U.S.) +8. +illumi gene ® Herpes Simplex Virus I & II – expected fiscal 2015 +Additional illumi gene tests in early-stage research and development include foodborne pathogens such as Campylobacter +jejuni , and bloodborne pathogens such as the causative agents for malaria. +We believe that our +illumi gene system has been well-accepted in our global markets. We currently have approximately 1,300 customer account placements. Of these account placements, over 1,150 accounts have completed evaluations and +validations and are regularly purchasing product, with the remaining account placements being in some stage of product evaluation and/or validation. Of our account placements, we have over 300 accounts that are multi-assay users. +- 7 - +Table of Contents +Market Trends +The global market for infectious disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide +standards of living and access to health care improve. More importantly, within this market, there is a continuing shift from conventional testing, which requires highly trained personnel and lengthy turnaround times for test results, to more +technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The increasing global +pressures to contain total health care costs have accelerated the increased use of diagnostic testing. With rapid and accurate diagnoses of infectious diseases, physicians can pinpoint appropriate therapies quickly, leading to faster recovery, +shorter hospital stays and lower overall treatment cost. The creation of Accountable Care Organizations (ACOs) in our U.S. market, in particular, has the goal of increasing efficiency of health care delivery, reducing spending and improving clinical +outcomes. We believe our product portfolio positions us competitively with ACOs and health care systems that are transitioning from fee-for-service compensation models, to compensation models based on the total outcome costs of a given patient. Our +C. difficile , Group B Streptococcus , Group A Streptococcus , and H. pylori products are all examples of how a highly accurate diagnostic test on the front end can mitigate or reduce down-stream costs for antibiotic use, +symptom-relieving drugs and hospital stays. +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group +purchasing organizations and integrated delivery networks, consolidation among reference laboratories, and acquisition of physician practices by hospitals. We utilize multi-year supply agreements to secure our business where possible and +appropriate. +Cost containment pressures have also affected health care systems outside the U.S., particularly in Europe, where the health care systems +are generally government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing and Focus Product Families +Our +Diagnostics segment’s sales and distribution network consists of the following for each of the broad geographic regions we serve: +North America +In North +America, our sales and distribution network consists of a direct sales force (U.S. only) complemented by independent distributors. The use of independent distributors in the U.S. allows our products to reach any size health care facility and also +provides our customers the option to purchase our +- 8 - +Table of Contents +products direct or through distribution along with other supplies. Two independent distributors in the U.S. accounted for 10% or more of consolidated net revenues in fiscal 2014, 2013 and 2012: +Cardinal Healthcare Corporation and Thermo Fisher Scientific. Our revenues from Cardinal were approximately $28,000, $35,000 and $33,000 during fiscal 2014, 2013 and 2012, respectively. Our revenues from Fisher were approximately $23,000, $25,000 +and $20,000 during fiscal 2014, 2013 and 2012, respectively. +EMEA +In EMEA, our sales and distribution network consists of direct sales forces in Belgium, France, Holland and Italy, and independent distributors +in other European countries, Africa and the Middle East. We are implementing a direct sales presence in Germany and the U.K. for our illumi gene products. We maintain a distribution center near Milan, Italy. +ROW +With the exception of +Australia and Singapore, in which we utilize a direct sales force, we utilize independent distributors throughout the ROW. +Our Diagnostics segment’s +focus product families are described below: +C. difficile +C. difficile , causative agent of serious hospital acquired bacterial infections, is our largest product family, generating approximately $35,000 in +global revenues for fiscal 2014, or a 12% decrease from fiscal 2013 – reflecting a combination of sales of our molecular-based and traditional immunoassay products. This product family has experienced significant competition in recent years +from new technologies, including other molecular testing platforms. See Competition discussion below. +Foodborne +Our foodborne product family achieved approximately $23,000 in global revenues for fiscal 2014, or a decrease of 3%, with over 95% of such sales occurring in +the U.S. Our foodborne products include tests for Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy). In the U.S. market, we believe that there are potentially 20 million stool cultures that are tested annually for +foodborne illnesses. We continue to believe that we have less than a 20% market share for EHEC and less than a 5% market share for Campy. +While +historically the primary competition for our foodborne products has been laboratory culture methods, during 2012 one of our competitors received FDA clearance for a shiga toxin test that competes with our EHEC test. We are continuing to re-emphasize +the benefits of increased sensitivity and faster turnaround time versus culture methods in our marketing programs, and believe that our test offers better workflow, less hands-on time and quicker results, in addition to being fully compliant with +CDC-recommended testing methods. +- 9 - +Table of Contents +Helicobacter pylori +H. pylori , a bacterium found in the stomach, is a major cause of peptic ulcers and is linked to duodenal ulcers and stomach cancer. +H. pylori represents our second largest product family, generating approximately $28,000 in global revenues for 2014, or 7% growth. We offer both antibody and direct antigen tests in alternative formats (single-use and high volume +batch). Our major competition in this product family is alternative test methods, serology and urea breath, and the prescription of symptom-relieving medications. Over 70% of our H. pylori product sales are in the U.S., where our strategy for +this product line has been to partner with managed care companies to promote the health and economic benefits of a test and treat strategy, and to move physician behavior away from serology-based testing toward direct antigen testing. In the U.S. +market, we believe that there are potentially 30 million people suffering from peptic ulcers and we believe that we currently have a 5% market share. +Our patents related to our H. pylori stool antigen tests expire in 2016 in the U.S. and 2017 in countries outside the U.S. Upon patent expiration, we +may be subject to competitive product introductions, which could lead to downward pressure on selling prices. +Competition +Our major competitors in molecular diagnostics are Cepheid and Becton Dickinson, who have systems with multiple-assay menus. We also face competition in +molecular diagnostics, but to a lesser degree, from companies such as Great Basin, Nanosphere and Quidel. These latter companies have a limited commercial menu and tend to compete strictly on price. We believe that our molecular platform offers a +number of competitive features: +• +Molecular assay sensitivity that is comparable to higher costing PCR; +• +Low capital investment with no instrument service cost; +• +Small footprint that is portable and does not consume much laboratory space; and +• +Product menu that fits with initiatives to improve clinical and economic outcomes. +Our major +competitors in rapid immunoassay diagnostics are primarily Alere and Quidel. These companies tend to compete strictly on price. We believe that the breadth and depth of our product portfolio provides us with a competitive advantage. For C. +difficile , we believe that we are the only company able to offer a full line of FDA-approved immunoassay (GDH and Toxin) and molecular products, allowing the customer to choose the solution that best suits them. +- 10 - +Table of Contents +Research and Development +Our Diagnostics segment’s research and development organization, which is located at our corporate headquarters in Newtown, Ohio, a suburb of +Cincinnati, has expertise in biochemistry, immunology, mycology, bacteriology, virology, parasitology and molecular biology. Research and development expenses for the Diagnostics segment for fiscal 2014, 2013 and 2012 were approximately $10,000, +$8,000 and $8,000, respectively. This research and development organization focuses its activities on new product and new technology development, new applications for our existing technologies, and improvements to existing products. Research and +development efforts may occur in-house or with collaborative partners. We believe that new product development is a key source for sustaining revenue growth. The products within our illumi gene molecular platform and H. +pylori product family were developed solely in-house. +Manufacturing +Our immunoassay and molecular products require the production of highly specific and sensitive antigens, antibodies, primers and enzymes. While +we produce substantially all of our own requirements including monoclonal and polyclonal antibodies, and a variety of fungal, bacterial and viral antigens, currently a number of the raw materials used in our products, including our +illumi gene molecular products, are purchased from outside vendors. With the recent completion of an expansion of our molecular diagnostic manufacturing capacity at our Cincinnati, Ohio location, we believe that we +have sufficient manufacturing and sourcing capacity for anticipated growth over the next several years. +Intellectual Property, +Patents and Licenses +We own or license U.S. and foreign patents, most of which are for products manufactured by our Diagnostics segment. Revenues +from these products are as follows: +Product/Technology Family +Number of +products +% of consolidated revenues +2014 +2013 +illumi gene +5 +20 +% +18 +% +H. pylori +2 +14 +% +13 +% +Respiratory +3 +2 +% +3 +% +Other +5 +1 +% +1 +% +Total patented products +15 +37 +% +35 +% +The patents for the illumi gene products expire between 2020 and 2022; the patents for the +two H. pylori products expire in 2016 in the U.S. and in 2017 for countries outside the U.S.; and the patents for the three respiratory products expire in 2022 (two products) and 2027. The remaining five patented products for which we own or +license patents are spread over three product families. +- 11 - +Table of Contents +In the absence of patent protection, we may be vulnerable to competitors who successfully replicate our +production and manufacturing technologies and processes. Our employees are required to execute confidentiality and non-disclosure agreements designed to protect our proprietary products. +Government Regulation +Our diagnostic products are +regulated by the Food & Drug Administration (FDA) as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (FDCA). Under the FDCA, medical devices are classified into one of three classes (i.e., Class I, II or III). Class +I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally must receive “pre-market approval” from the FDA as to safety and effectiveness. +Each of the diagnostic products currently marketed by us in the United States has been cleared by the FDA pursuant to the 510(k) clearance process or is +exempt from such requirements. We believe that most, but not all, products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all Class II devices, will be eligible for 510(k) clearance; +however, we can make no assurances in this regard. Meridian’s TRU FLU ® rapid influenza assay was cleared in 2006 as a Class I device. In May 2014, the FDA proposed reclassifying +rapid influenza assays as a Class II device, requiring the submission of a new 510(k) application and subjecting TRU FLU and similar competitive devices to increased requirements for sensitivity. Once the proposed rule becomes effective, +Meridian will have one year to bring its assay up to the new requirements or remove it from the market. Sales of the TRU FLU product totaled approximately $2,500 in fiscal 2014. +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, largely similar to that of the FDA. +Meridian’s Cincinnati manufacturing facility is certified to ISO 13485:2012. +Medical Device Tax +On January 1, 2013, the +medical device tax established as part of the U.S. health care reform legislation became effective and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2014 and 2013, the Company recorded to +cost of sales approximately $1,750 and $1,300, respectively, of medical device tax expense related to this legislation. +Seasonal Factors and +Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper +respiratory and parasitic infectious diseases. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses, or pandemics such as the H1N1 +- 12 - +Table of Contents +influenza outbreak during fiscal 2009. While we believe that the breadth of our diagnostic product lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause +significant variability in diagnostic revenues, we can make no assurance that revenues will not be impacted period over period by such factors. +Life +Science Segment +Overview of Products and Markets +Our Life Science segment’s business focuses on the development, manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, +nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies, as well as contract development and manufacturing services under clinical cGMP conditions. Third-party revenues for this segment +were approximately $47,000, $44,000 and $43,000 for fiscal 2014, 2013 and 2012, respectively. As of September 30, 2014, our Life Science segment had approximately 200 employees in five countries. +Most of the revenues for our Life Science segment currently come from the manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, +nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies focused on the development of immunoassay and molecular tests. Approximately 65% of Life Science revenues are generated from the +industrial market, defined as diagnostic manufacturers and the agriculture industry. This is an increasing focus for our Bioline molecular component business, which historically focused on the academic/research market that comprises the remaining +35% of revenues. We utilize direct sales teams in key countries such as the U.S., the U.K., Germany, France, Australia and Singapore. Opened in 2013, the Singapore sales and business development office is designed to increase our presence and our +revenue opportunities in Asia for both molecular and immunoassay components. Additionally, in order to further pursue revenue opportunities in Asia, and China in particular, we are in the process of opening a representative office in Beijing, China. +We utilize a network of distributors in other major countries. During fiscal 2014, 16% of third-party revenues for this segment were from two diagnostic manufacturing customers. +Products such as antibodies, antigens and reagents are marketed primarily to diagnostic manufacturing customers as a source of raw materials for their +immunoassay products, or as an outsourced step in their manufacturing processes. For example, we supply a number of major diagnostic manufacturers with proteins used to detect hepatitis A and rubella. These products are typically sold in bulk +quantities, and may also be custom-designed for a particular manufacturer’s requirements. Sales efforts are focused on multi-year supply arrangements in order to provide stability in volumes and pricing. We believe this benefits both us and our +customers. +- 13 - +Table of Contents +Molecular biology products such as PCR/qPCR reagents, nucleotides and competent cells are marketed to +academic/research and industrial customers. These products are used in measuring DNA and RNA in clinical and agricultural applications. These reagents improve the purity, yield and speed of PCR reactions. Products such as MyTaq™ and +SensiFAST™ are examples of this type of PCR/qPCR reagent. +Our clinical cGMP protein production facility in Memphis, Tennessee serves as an enabling +technology for process development and large-scale manufacturing for biologicals used in new drugs and vaccines. The size of the facility is intended to accommodate manufacturing requirements for Phase I and Phase II clinical trials for +biopharmaceutical, biotechnology and government agency customers. Our revenues for contract services were approximately $3,000, $3,000 and $2,000 in fiscal 2014, 2013 and 2012, respectively. +Market Trends +Globally, sales of molecular +components are growing at a faster pace than immunoassay components, and this is consistent with our business. Geographic expansion is a significant strategy for our Life Science segment, along with further penetration into industrial markets with +our molecular products. +Competition +The +market for bulk biomedical reagents is highly competitive. Important competitive factors include product quality, price, customer service, and reputation. We face competitors, many of which have greater financial, research and development, sales and +marketing, and manufacturing resources, and where sole-source supply arrangements do not exist. From time to time, customers may choose to manufacture their biomedical reagents in-house rather than purchase from outside vendors such as Meridian. +The academic/research market is highly fragmented. Individual purchases are typically of small quantities. The breadth of product offerings, quality, +price and service, including on-line capabilities and technical resources, are important factors to building customer loyalty and repeat purchases. +The +market for contract manufacturing in a validated cGMP facility, such as our Memphis facility, is also competitive. Important competitive factors include reputation, customer service and price. Although the product application for this facility was +built from our existing expertise in cell culture manufacturing techniques, we face competitors with greater experience in contract manufacturing in a clinical cGMP environment. +Research and Development +Research and development +expenses for our Life Science segment for fiscal 2014, 2013 and 2012 were approximately $3,000, $3,000 and $2,000, respectively. This research and development organization is heavily involved in vaccine development and production activities for our +cGMP facility and development of new molecular products. +- 14 - +Table of Contents +Manufacturing and Government Regulation +Our Life Science facilities are ISO 9001:2008 certified, and where appropriate, comply with Regulation EC 1069:2009. +The cGMP clinical grade proteins that are produced in our Memphis facility are intended to be used as “injectibles,” and, as such, they are produced +under cGMP Regulations for Biologics and Human Drugs under the auspices of the FDA. Following clinical trials, approval and licensing of these products is the responsibility of the applicant, who owns the rights to each protein. Typically, the +customer is the applicant, not Meridian Life Science. +Acquisitions +Acquisitions have played an important role in the growth of our businesses. Our acquisition objectives include, among other things, (i) enhancing product +offerings; (ii) improving product distribution capabilities; (iii) providing access to new markets; and/or (iv) providing access to key biologicals or new technologies that lead to new products. Although we cannot provide any +assurance that we will consummate any additional acquisitions in the future, nor can we provide any assurance that any acquisitions will accomplish these objectives, we expect that the potential for acquisitions will continue to provide +opportunities for revenues and earnings growth in the future. +International Markets +International markets are an important source of revenues and future growth opportunities for both of our segments. For both segments combined, revenues from +customers located outside of North America approximated $55,000 or 29% of consolidated fiscal 2014 revenues, $54,000 or 29% of consolidated fiscal 2013 revenues and $53,000 or 31% of consolidated fiscal 2012 revenues. We expect to continue to look +to international markets as a source of new revenues and growth in the future. +Environmental +We are a conditionally exempt, small quantity generator of hazardous waste and have a U.S. EPA identification number. We are in compliance with applicable +portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. +- 15 - +Table of Contents +ITEM 1A. +RISK FACTORS +In addition to the other +information set forth in this report, you should carefully consider the following factors, which could materially affect our business, financial condition, cash flows or future results. Any one of these factors could cause our actual results to vary +materially from recent results or from anticipated future results. The risks described below are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may +materially adversely affect our business, financial condition and/or operating results. +Risks Affecting Growth and Profitability of our Business +We may be unable to develop new products and services or acquire products and services on favorable terms. +The medical diagnostic and life science industries are characterized by ongoing technological developments and changing customer requirements. As such, our +results of operations and continued growth depend, in part, on our ability in a timely manner to develop or acquire rights to, and successfully introduce into the marketplace, enhancements of existing products and services or new products and +services that incorporate technological advances, meet customer requirements and respond to products developed by our competition. We cannot provide any assurance that we will be successful in developing or acquiring such rights to products and +services on a timely basis, or that such products and services will adequately address the changing needs of the marketplace, either of which could adversely affect our results of operations. +In addition, we must regularly allocate considerable resources to research and development of new products, services and technologies. The research and +development process generally takes a significant amount of time from design stage to product launch. This process is conducted in various stages. During each stage, there is a risk that we will not achieve our goals on a timely basis, or at all, +and we may have to abandon a product in which we have invested substantial resources. +We may be unable to successfully integrate operations or to +achieve expected cost savings from acquisitions we make. +One of our growth strategies is the acquisition of companies and/or products. Although +additional acquisitions of companies and products may enhance the opportunity to increase net earnings over time, such acquisitions could result in greater administrative burdens, increased exposure to the uncertainties inherent in marketing new +products and financial risks of additional operating costs. The principal benefits expected to result from any acquisitions we make will not be achieved fully unless we are able to successfully integrate the operations of the acquired entities with +our operations and realize the anticipated synergies, cost savings and growth opportunities from integrating these businesses into our existing businesses. We cannot provide any assurance that we will be able to identify and complete additional +acquisitions on terms we consider favorable or that, if completed, will be successfully integrated into our operations. +- 16 - +Table of Contents +Revenues for our Diagnostics segment may be impacted by our reliance upon two key distributors in North +America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +Key Distributors +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 36% and 42%, respectively, of the Diagnostics segment’s total +revenues for fiscal 2014 and fiscal 2013, or 27% and 32%, respectively, of our consolidated revenues for fiscal 2014 and fiscal 2013. These parties distribute our products and other laboratory products to end-user customers. The loss of either of +these distributors could negatively impact our revenues and results of operations unless suitable alternatives were timely found or lost sales to one distributor were absorbed by another distributor. Finding a suitable alternative on satisfactory +terms may pose challenges in our industry’s competitive environment. As an alternative, we could expand our efforts to distribute and market our products directly. This alternative, however, would require substantial investment in additional +sales, marketing and logistics resources, including hiring additional sales and customer service personnel, which would significantly increase our future selling, general and administrative expenses but would not necessarily result in lower net +income levels. +In addition, buying patterns of these two distributors may fluctuate from quarter to quarter, potentially leading to uneven concentration +levels on a quarterly basis. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory and parasitic infectious +diseases. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses, or pandemics such as H1N1 influenza. While we believe that the breadth of our diagnostic product +lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be negatively impacted period over period by such +factors. +Changing Diagnostic Market Conditions +Changes in the U.S. health care delivery system have resulted in consolidation among reference laboratories and the formation of multi-hospital alliances, +reducing the number of institutional customers for diagnostic test products. Consolidation in the U.S. health care industry has also led to the creation of group purchasing organizations (GPOs) and integrated delivery networks (IDNs) that aggregate +buying power for hospital groups and put pressure on our selling prices. Due to such consolidation, we may not be able to enter into and/or sustain contractual or other marketing or distribution arrangements on a satisfactory commercial basis with +institutional customers, GPOs and IDNs, which could adversely affect our results of operations. +- 17 - +Table of Contents +We could be adversely affected by health care reform legislation. +Third-party payers for medical products and services, including state, federal and foreign governments, are increasingly concerned about escalating health care +costs and can indirectly affect the pricing or the relative attractiveness of our products by regulating the maximum amount of reimbursement they will provide for diagnostic testing services. Following years of increasing pressure, during 2010 the +U.S. government enacted comprehensive health care reform. At present, given the early stages of the enacted reform, we are unable to predict what effect the legislation might ultimately have on reimbursement rates for our products. If reimbursement +amounts for diagnostic testing services are decreased in the future, such decreases may reduce the amount that will be reimbursed to hospitals or physicians for such services and consequently could place constraints on the levels of overall pricing, +which could have a material effect on our revenues and/or results of operations. +In addition, on January 1, 2013, the medical device tax established +as part of the U.S. health care reform legislation became effective and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2014 and 2013, the Company recorded approximately $1,750 and $1,300, +respectively, of Medical Device Tax expense, which is reflected as a component of cost of sales in the accompanying Consolidated Statements of Operations. +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +As part of the Budget Control Act passed in August 2011 to extend the federal debt limit and reduce government spending, $1.2 trillion in automatic spending +cuts (known as sequestration) over the next decade have gone into effect, beginning in 2013, and will remain in effect in the absence of further legislative action. Half of the automatic reductions will come from lowering the caps imposed on +non-defense discretionary spending and cutting domestic entitlement programs, including reductions in payments to Medicare providers. Government research funding has also been reduced as a result of sequestration. Such reductions in government +health care spending or research funding could result in reduced demand for our products or additional pricing pressure. Further, there is ongoing uncertainty regarding the federal budget and federal spending levels, including the possible impacts +of a failure to increase the “debt ceiling.” Any U.S. government default on its debt could have broad macroeconomic effects that could, among other things, raise our borrowing costs. Any future shutdown of the federal government or failure +to enact annual appropriations could also have a material adverse impact on our business. +Revenues for our Life Science segment may be impacted by +customer concentrations and buying patterns. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two +diagnostic manufacturing customers were 16% and 17%, respectively, of the Life Science segment’s total revenues for fiscal 2014 and fiscal 2013, or 4% and 4%, respectively, of our consolidated revenues for fiscal 2014 and fiscal 2013. Our Life +Science segment has four other significant customers who purchase antigens, antibodies and reagents, which together comprised 8% of the segment’s total revenues for each of fiscal 2014 and fiscal 2013. Any significant alteration of buying +patterns from these customers could adversely affect our period over period revenues and results of operations. +- 18 - +Table of Contents +Revenues relating to research, development and manufacturing services for our Life Science segment are generated +on a contract by contract basis. The nature of this business is such that each contract provides a unique product and/or service and corresponding revenue stream. While this business has historically generated annual revenues of approximately $2,000 +to $4,000, there can be no assurance that future contracts will be secured, and if secured, will be profitable. +Intense competition could adversely +affect our profitability. +The markets for our products and services are characterized by substantial competition and rapid change. Hundreds of +companies around the world supply diagnostic tests and purified reagents. These companies range from multinational health care entities, for which diagnostics is one line of business, to small start-up companies. Many of our competitors have +significantly greater financial, technical, manufacturing and marketing resources than we do. We cannot provide any assurance that our products and services will be able to compete successfully with the products and services of our competitors. +We may face increased competition upon expiration of our H. pylori patents in 2016 and 2017. +Our patents related to our H. pylori stool antigen tests expire in 2016 in the U.S. and 2017 in countries outside the U.S. Upon patent +expiration, we may be subject to competitive product introductions, which could lead to downward pressure on selling prices. Our global revenues for H. pylori products were $28,000 in fiscal 2014. +We depend on international revenues, and our financial results may be adversely impacted by foreign currency, regulatory or other developments affecting +international markets. +We sell products and services into approximately 60 countries. Approximately 29% of our net revenues for both fiscal 2014 +and 2013 were attributable to markets outside of North America. For fiscal 2014, approximately 40% of our international revenues were from sales made in Euros and 40% were from sales made in U.S. dollars, with the remaining 20% primarily being a +combination of sales made in British pounds and Australian dollars. We are subject to the risks associated with fluctuations in the exchange rates for the Australian dollar, British pound, Euro and Singapore dollar to the U.S. dollar. We are also +subject to other risks associated with international operations, including longer customer payment cycles, tariff regulations, requirements for export licenses, instability of foreign governments, and governmental requirements with respect to the +importation and distribution of medical devices and immunodiagnostic and molecular biology reagents, all of which may vary by country. +- 19 - +Table of Contents +Risks Affecting our Manufacturing Operations +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +Medical device diagnostics and the manufacture, sale and distribution of bulk antigens, antibodies and reagents are highly regulated industries. We cannot +provide any assurance that we will be able to obtain necessary governmental clearances or approvals or timely clearances or approvals to market future products in the United States and other countries. Costs and difficulties in complying with laws +and regulations administered by the U.S. Food and Drug Administration, the U.S. Department of Agriculture, the U.S. Department of Commerce, the U.S. Drug Enforcement Agency, the Centers for Disease Control or other regulators can result in +unanticipated expenses and delays and interruptions to the sale of new and existing products. +Regulatory approval can be a lengthy, expensive and +uncertain process, making the timing and costs of approvals difficult to predict. The failure to comply with these regulations can result in delay in obtaining authorization to sell products, seizure or recall of products, suspension or revocation +of authority to manufacture or sell products, and other civil or criminal sanctions. +Significant interruptions in production at our principal +manufacturing facilities and/or third-party manufacturing facilities would adversely affect our business and operating results. +Products and +services manufactured at facilities we own or lease comprised a majority of our revenues. Our global supply of these products and services is dependent on the uninterrupted and efficient operation of these facilities. In addition, we currently rely +on a small number of third-party manufacturers to produce certain of our diagnostic products and product components. The operations of our facilities or these third-party manufacturing facilities could be adversely affected by power failures, +natural or other disasters, such as earthquakes, floods, tornadoes or terrorist threats. Although we carry insurance to protect against certain business interruptions at our facilities, there can be no assurance that such coverage will be adequate +or that such coverage will continue to remain available on acceptable terms, if at all. Any significant interruption in the Company’s or a third-party supplier’s manufacturing capabilities could materially and adversely affect our +operating results. +We depend on sole-source suppliers for certain critical raw materials and components, and finished products. A supply +interruption could adversely affect our business. +Raw Materials and Components +Our diagnostic products are made from a wide variety of raw materials that are biological or chemical in nature, and that generally are available from multiple +sources of supply. We sole-source certain raw materials and components due to FDA regulations, which make it time consuming and costly to switch raw materials and components in FDA cleared products. If certain suppliers fail to supply required raw +materials or components, we will need to secure other sources which may require us to conduct additional development and testing and obtain regulatory approval. These activities require significant time and resources, and there is no assurance that +new sources will be secured or regulatory approvals, if necessary, will be obtained. +- 20 - +Table of Contents +One third party manufactures our proprietary illumi pro-10™ +Incubator Reader (instrument), a component of our illumi gene molecular system. This instrument is manufactured exclusively for Meridian according to our specifications, with the cost of each instrument being relatively +inexpensive. While other manufacturers for this type of instrument are available, we source solely from one manufacturer due to the FDA regulations and costs involved in clearing the system for marketing in the United States. If this third-party +manufacturer fails to supply us with instruments, we will need to secure another manufacturer, and it may take as long as 12 months to transfer instrument manufacturing. As revenues for our illumi gene molecular system accounted +for $37,000 or 20% of consolidated revenues for fiscal 2014, $34,000 or 18% for fiscal 2013 and $23,000 or 13% for fiscal 2012, an interruption in the manufacturing of this system could have a material adverse effect on our operating results. +Additionally, one third party manufactures one certain reagent for use with our illumi gene assays. While +alternative suppliers exist, we elect to utilize this third party exclusively in order to maintain consistency in our materials, which is critical in complying with FDA regulatory requirements. +Finished Products +We outsource the manufacturing +for certain finished diagnostic products to third parties. A disruption in the supply of these finished products could have a material adverse effect on our business until we find another supplier or bring manufacturing in house. +Three products manufactured exclusively for us by two separate and independent companies accounted for 14%, 14% and 13% of consolidated revenues in fiscal +2014, 2013, and 2012, respectively. Meridian owns all rights and title to the FDA 510(k) clearances for these products. +Activities undertaken by Meridian +to reduce the risk of these sole-supplier arrangements include maintaining adequate inventory levels, supplier qualification procedures, supplier audits, site visits and frequent communication. Additionally, we have identified potential alternate +suppliers. +Risks Related to Intellectual Property and Product Liability +We may be unable to protect or obtain proprietary rights that we utilize or intend to utilize. +In developing and manufacturing our products, we employ a variety of proprietary and patented technologies. In addition, we have licensed, and expect to +continue to license, various complementary technologies and methods from academic institutions and public and private companies. We cannot provide any assurance that the technologies that we own or license provide protection from competitive threats +or from challenges to our intellectual property. In addition, we cannot provide any assurances that we will be successful in obtaining and retaining licenses or proprietary or patented technologies in the future. +- 21 - +Table of Contents +Product infringement claims by other companies could result in costly disputes and could limit our ability +to sell our products. +Litigation over intellectual property rights is prevalent in the diagnostic industry. As the market for diagnostics +continues to grow and the number of participants in the market increases, we may increasingly be subject to patent infringement claims. It is possible that a third-party may claim infringement against us. If found to infringe, we may attempt to +obtain a license to such intellectual property; however, we may be unable to do so on favorable terms, or at all. Additionally, if our products are found to infringe on third-party intellectual property, we may be required to pay damages for past +infringement and lose the ability to sell certain products, causing our revenues to decrease. We currently carry intellectual property insurance that covers damages and defense costs from our potential infringement on certain other third-party +patents at levels that we believe are commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect +on our profitability and the damage to our reputation in the industry could have a material adverse effect on our business. +If product liability +lawsuits are successfully brought against us, we may incur substantial liabilities and may have to limit or cease sales of our products. +The +testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be +required to limit or cease sales of our products. We currently carry product liability insurance at a level we believe is commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. In certain +customer contracts, we indemnify third-parties for certain product liability claims related to our products. These indemnification obligations may cause us to pay significant sums of money for claims that are covered by these indemnifications. In +addition, a defect in the design or manufacture of our products could have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from +such a claim could have a material adverse effect on our profitability and the damage to our reputation in the industry could have a material adverse effect on our business. +Other Risks Affecting Our Business +Our business +could be negatively affected if we are unable to attract, hire and retain key personnel. +Our future success depends on our continued ability to +attract, hire and retain highly qualified personnel, including our executive officers and scientific, technical, sales and marketing employees, and their ability to manage growth successfully. If such key employees were to leave and we were unable +to obtain adequate replacements, our operating results could be adversely affected. +- 22 - +Table of Contents +Our bank credit agreement imposes restrictions with respect to our operations. +Our bank credit agreement contains a number of financial covenants that require us to meet certain financial ratios and tests. If we fail to comply with the +obligations in the credit agreement, we would be in default under the credit agreement. If an event of default is not cured or waived, it could result in acceleration of any indebtedness under our credit agreement, which could have a material +adverse effect on our business. At the present time, no borrowings are outstanding under our bank credit agreement. +We face risks related to global +economic conditions. +We currently generate significant operating cash flows, which combined with access to the credit markets, provides us with +discretionary funding capacity for research and development and other strategic activities. However, as an enterprise with global operations and markets, our operations and financial performance are in part dependent upon global economic conditions, +and we could be negatively impacted by a global, regional or national economic crisis, including sovereign risk in the event of deterioration in the credit worthiness of or a default by local governments. We are particularly susceptible to the +economic conditions in countries where government-sponsored health care systems are the primary payers for health care, including those countries within the European Union that are reducing their public expenditures in an effort to achieve cost +savings. The uncertainty in global economic conditions poses a risk to the overall economy that could impact demand for our products, as well as our ability to manage normal commercial relationships with our customers, suppliers and creditors, +including financial institutions. As such, if global economic conditions deteriorate significantly, our business could be negatively impacted, including such areas as reduced demand for our products from a slow-down in the general economy, supplier +or customer disruptions resulting from tighter credit markets and/or temporary interruptions in our ability to conduct day-to-day transactions through our financial intermediaries involving the payment to or collection of funds from our customers, +vendors and suppliers. While to-date such factors have not had a significant negative impact on our results or operations, we continue to monitor and plan for the potential impact of these global economic factors. +Approximately $2,700 of our accounts receivable at September 30, 2014 is due from Italian hospital customers whose funding ultimately comes from the +Italian government, which is down from approximately $3,500 at September 30, 2013. +Breaches of our information technology systems could have a +material adverse effect on our operations. +We rely on information technology systems to process, transmit, and store electronic information in our +day-to-day operations. Like many multinational corporations, our information technology systems may be subjected to computer viruses or other malicious codes, unauthorized access attempts, and cyber- or phishing-attacks. We also store certain +information with third parties that could be subject to these types of attacks. Such attacks could result in our intellectual property and other confidential information being lost or stolen, disruption of our operations, and other negative +consequences, such as increased costs for security measures or remediation costs, and diversion of management attention. While we will continue to implement additional protective measures to +- 23 - +Table of Contents +reduce the risk of and detect cyber incidents, cyber-attacks are becoming more sophisticated and frequent, and the techniques used in such attacks change rapidly. There can be no assurances that +our protective measures will prevent attacks that could have a significant impact on our business. +Natural disasters, war and other events could +adversely affect our future revenues and operating income. +Natural disasters (including pandemics), war, terrorism, labor disruptions and +international conflicts, and actions taken by the United States and other governments or by our customers or suppliers in response to such events, could cause significant economic disruption and political and social instability in the United States +and in areas outside of the United States in which we operate. These events could result in decreased demand for our products, adversely affect our manufacturing and distribution capabilities, or increase the costs for or cause interruptions in the +supply of materials from our suppliers. +Risks Related to Our Common Stock +Our board of directors has the authority to issue up to 1,000 shares of undesignated preferred stock and to determine the rights, preferences, privileges and +restrictions, including voting rights, of such shares without any future vote or action by the shareholders. The issuance of preferred stock under certain circumstances could have the effect of delaying or preventing a change in control of our +company. Ohio corporation law contains provisions that may discourage takeover bids for our company that have not been negotiated with the board of directors. Such provisions could limit the price that investors might be willing to pay in the future +for shares of our common stock. In addition, sales of substantial amounts of such shares in the public market could adversely affect the market price of our common stock and our ability to raise additional capital at a price favorable to us. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Our corporate offices, +Diagnostics manufacturing facility and Diagnostics research and development facility are located in five buildings totaling approximately 120,000 square feet on 10 acres of land in the Village of Newtown, a suburb of Cincinnati, Ohio. These +properties are owned by us. We also operate a Diagnostics sales and distribution center near Milan, Italy in an approximately 18,000 square foot two-story building. This facility is owned by our wholly-owned Italian subsidiary, Meridian Bioscience +Europe s.r.l. We also rent office space in Paris, France; and Braine-l’Alleud, Belgium for sales and administrative functions. +- 24 - +Table of Contents +Our Life Science operations are conducted in several facilities in Memphis, Tennessee; Boca Raton, Florida; +Taunton, Massachusetts; London, England; Luckenwalde, Germany; Sydney, Australia; Singapore; and Beijing, China. Our facility in Memphis, Tennessee consists of two buildings totaling approximately 44,000 square feet and is owned by us. Our leased +facility in Boca Raton, Florida contains approximately 7,500 square feet of manufacturing space. In addition, we continue to own an approximately 23,000 square foot facility in Saco, Maine, which we have been marketing for sale or lease. Following +are details of our other Life Science facilities, all of which are leased: Taunton – approximately 10,000 square feet of sales and warehouse space; London – approximately 20,000 square feet of sales, warehouse, distribution, research and +development, manufacturing and administrative office space; Luckenwalde – approximately 10,000 square feet of sales, warehouse and manufacturing space; Sydney – approximately 4,000 square feet of sales, warehouse, research and development +and manufacturing space; Singapore – approximately 1,000 square feet of sales and business development space; Beijing – less than 1,000 square feet of representative office space maintained for business development purposes. +ITEM 3. +LEGAL PROCEEDINGS +We are a party to +various litigation matters that we believe are in the normal course of business. The ultimate resolution of these matters is not expected to have a material adverse effect on our financial position, results of operations or cash flows. No material +provision has been made in the accompanying consolidated financial statements for these matters. +ITEM 4. +MINE SAFETY DISCLOSURES +Not +applicable. +- 25 - +Table of Contents +PART II. +ITEM 5. +MARKET FOR REGISTRANT’S COMMON +EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Refer to “Forward Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on Pages 16 +through 24 of this Annual Report. +“Common Stock Information” on the inside back cover of the Annual Report to Shareholders for 2014 and +“Quarterly Financial Data (Unaudited)” relating to our dividends in Note 9 to the Consolidated Financial Statements are incorporated herein by reference. Except as may otherwise be prohibited by applicable law, there are no restrictions on +cash dividend payments. +During fiscal 2014, our indicated annual dividend rate of $0.80 per share approximated 96% of full year diluted earnings per +share, exceeding our long-standing policy of establishing a cash dividend payout ratio of between 75% and 85% of each fiscal year’s expected net earnings. Despite there being certain individual fiscal years in which our payout ratio has fallen +outside of this policy range, since adopting this policy in November 2002, our cumulative cash dividend payout has approximated 84% of cumulative net earnings during this timeframe. The declaration and amount of dividends will be determined by the +board of directors in its discretion based upon its evaluation of earnings, cash flow requirements and future business developments and opportunities, including acquisitions. At its meeting on November 5, 2014, the board of directors announced +a continuation of the $0.80 indicated annual dividend rate per share for fiscal 2015. We paid dividends of $0.79 per share in fiscal 2014 and $0.76 per share in each of fiscal 2013 and 2012. +As of September 30, 2014, there were approximately 850 holders of record and approximately 17,500 beneficial owners of our common shares. +ITEM 6. +SELECTED FINANCIAL DATA +Incorporated by +reference from inside front cover of the Annual Report to Shareholders for 2014. +- 26 - +Table of Contents +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Refer to “Forward Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on Pages 16 +through 24 of this Annual Report. +In the discussion that follows, all amounts are in thousands (both tables and text), except per share data . +Results of Operations : +Fourth Quarter +Net earnings for the fourth quarter of fiscal 2014 decreased 11% to $8,182, or $0.20 per diluted share, from net earnings for the fourth quarter +of fiscal 2013 of $9,150, or $0.22 per diluted share. This decrease reflects the combined effects of decreased revenues, decreased gross profit margins and decreased operating expenses, along with $429 (pre-tax) of stock-based compensation expense +related to the accelerated vesting of certain stock-based awards held by the our Executive Chairman at the time of his death in the fourth quarter of fiscal 2014. Consolidated revenues for the fourth quarter of fiscal 2014 were $46,692, a decrease +of $2,270, or 5%, compared to the fourth quarter of fiscal 2013. +Included within the fourth quarter 2014 results were revenues from our +illumi gene ® molecular platform of products totaling $9,116, representing a 3% decrease from the fiscal 2013 fourth quarter. Also contributing to the consolidated revenues +decrease were decreased revenues in two of our diagnostic focus product families ( C. difficile and foodborne) and flat revenues for our H. pylori focus product family. Serving to partially offset these decreases were increased revenues +in our respiratory product family and both of our Life Science segment’s business lines (i.e., molecular component and immunoassay component). +Revenues for the Diagnostics segment for the fourth quarter of fiscal 2014 decreased 8% compared to the fourth quarter of fiscal 2013, reflecting the +following for each of our focus product families: flat revenues in our H. pylori products, 7% decline in our foodborne products, and 18% decline in our C. difficile products. In addition, we experienced 7% growth in our respiratory +products from the comparable fiscal 2013 period. With growth in both its molecular component and immunoassay component business, revenues of our Life Science segment increased by 5% during the fourth quarter of fiscal 2014 compared to the fourth +quarter of fiscal 2013. +Fiscal Year +Net earnings for fiscal 2014 decreased 9% to $34,743, or $0.83 per diluted share, from net earnings for fiscal 2013 of $38,032, or $0.91 per diluted share. +This decrease reflects the combined effects of flat revenue growth, decreased gross profit margins and slightly increased operating expenses, along with an approximate $425 (pre-tax) negative effect from medical device tax that did not exist during +the first quarter of fiscal 2013 (see discussion in Medical Device Tax below). +- 27 - +Table of Contents +REVENUE OVERVIEW +Below are analyses of the Company’s revenue, provided for each of the following: +• +By Reportable Segment & Geographic Region +• +By Product Platform/Type +• +By Disease Family (Diagnostics only) +Revenue Overview- By Reportable Segment & Geographic +Region +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, +and the sale and distribution of diagnostic test kits in the U.S. and Canada (“North America”); Europe, Middle East and Africa (“EMEA”); and other countries outside of North America and EMEA (rest of the world, or +“ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, +PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically and abroad, including a sales and business development location in Singapore. Additionally, in order to further pursue revenue opportunities in Asia, and China in +particular, our Life Science segment is in the process of opening a representative office in Beijing, China. The Life Science segment also includes the contract development and manufacture of cGMP clinical grade proteins and other biologicals for +use by biopharmaceutical and biotechnology companies engaged in research for new drugs and vaccines. +Revenues for the Diagnostics segment, in the normal +course of business, may be affected from quarter to quarter by buying patterns of major distributors, seasonality and strength of certain diseases, and foreign currency exchange rates. Revenues for the Life Science segment, in the normal course of +business, may be affected from quarter to quarter by the timing and nature of arrangements for contract services work, which may have longer production cycles than bioresearch reagents and bulk antigens and antibodies, as well as buying patterns of +major customers, and foreign currency exchange rates. We believe that the overall breadth of our product lines serves to reduce the variability in consolidated revenues from these factors. +- 28 - +Table of Contents +Revenues for each of our segments and the geographic regions therein are shown below. +2014 vs. +2013 +2013 vs. +2012 +2014 +2013 +2012 +Inc (Dec) +Inc (Dec) +Diagnostics- +North America +$ +114,754 +$ +116,509 +$ +101,391 +(2 +)% +15 +% +EMEA +21,807 +21,378 +22,267 +2 +% +(4 +)% +ROW +4,939 +6,742 +6,522 +(27 +)% +3 +% +Total Diagnostics +141,500 +144,629 +130,180 +(2 +)% +11 +% +Life Science- +North America +19,040 +17,688 +17,917 +8 +% +(1 +)% +EMEA +20,005 +18,721 +18,050 +7 +% +4 +% +ROW +8,287 +7,648 +6,565 +8 +% +16 +% +Total Life Science +47,332 +44,057 +42,532 +7 +% +4 +% +Consolidated +$ +188,832 +$ +188,686 +$ +172,712 +— +% +9 +% +% of total revenues- +Diagnostics +75 +% +77 +% +75 +% +Life Science +25 +% +23 +% +25 +% +Total +100 +% +100 +% +100 +% +Ex-North America +29 +% +29 +% +31 +% +- 29 - +Table of Contents +Revenue Overview- By Product Platform/Type +The revenues generated by each of our reportable segments result primarily from the sale of the following segment-specific categories of products: +Diagnostics +1) Molecular tests that operate on our illumi gene platform +2) Immunoassay tests +Life Science +1) Molecular components +2) Immunoassay components +Revenues for each product platform/type, as well as its relative percentage of segment revenues, are shown below. +2014 +2013 +2012 +2014 vs. +2013 +Inc (Dec) +2013 vs. +2012 +Inc (Dec) +Diagnostics- +Molecular +$ +36,981 +$ +33,597 +$ +23,248 +10 +% +45 +% +Immunoassay +104,519 +111,032 +106,932 +(6 +)% +4 +% +Total Diagnostics +$ +141,500 +$ +144,629 +$ +130,180 +(2 +)% +11 +% +Life Science- +Molecular components +$ +20,824 +$ +18,777 +$ +17,078 +11 +% +10 +% +Immunoassay components +26,508 +25,280 +25,454 +5 +% +(1 +)% +Total Life Science +$ +47,332 +$ +44,057 +$ +42,532 +7 +% +4 +% +% of Diagnostics revenues- +Molecular +26 +% +23 +% +18 +% +Immunoassay +74 +% +77 +% +82 +% +Total Diagnostics +100 +% +100 +% +100 +% +% of Life Science revenues- +Molecular components +44 +% +43 +% +40 +% +Immunoassay components +56 +% +57 +% +60 +% +Total Life Science +100 +% +100 +% +100 +% +Following is a discussion of the revenues generated by each of these product platforms/types: +Diagnostics Products +illumi gene Molecular Platform Products +We have approximately 1,300 customer account placements. Of these account placements, over 1,150 accounts have completed evaluations and validations and are +regularly purchasing product, with the balance of our account placements being in some stage of product evaluation and/or validation. Of our account placements, we have over 300 accounts that are regularly purchasing, evaluating and/or validating +two or more assays. +- 30 - +Table of Contents +We continue to invest in new product development for our molecular testing platform, +illumi gene . This platform now has five commercialized tests, with three additional tests expected to be available for sale in fiscal 2015: +1. +illumi gene ® C. difficile – commercialized in August 2010 +2. +illumi gene ® Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene ® Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene ® Mycoplasma ( M. pneumonia ; walking pneumonia) – commercialized in June 2013 +5. +illumi gene ® Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene ® Chlamydia trachomatis – expected fiscal 2015 (launch outside of U.S.) +7. +illumi gene ® Neisseria gonorrhea – expected fiscal 2015 (launch outside of U.S.) +8. +illumi gene ® Herpes Simplex Virus I & II – expected fiscal 2015 +Additional illumi gene tests in early-stage research and development include foodborne pathogens such as Campylobacter +jejuni , and bloodborne pathogens such as the causative agents for malaria. +We believe that the diagnostic testing market is +continuing to move away from culture and immunoassay testing to molecular testing for diseases where there is a favorable cost/benefit position for the total cost of health care. While this market is competitive, with molecular companies such as +Cepheid and Becton Dickinson and new entrants such as Quidel, Great Basin, Nanosphere, and others, we believe we are well positioned to capitalize on the migration to molecular testing. Our simple, easy-to-use, +illumi gene platform, with its expanding menu, requires no expensive equipment purchase and little to no maintenance cost. We believe these features, along with its small footprint and the performance of the +illumi gene assays, make illumi gene an attractive molecular platform to any size hospital or physician office laboratory. +Immunoassay Products +Revenues from our +Diagnostics segment’s immunoassay products decreased 6% in fiscal 2014, following a 4% increase in fiscal 2013. As described in the product discussions below, the current year decrease results primarily from the decline in revenues from our +C. difficile , foodborne and respiratory products, partially offset by the growth in revenues from our H. pylori products. +Life +Science Products +During fiscal 2014, revenues from our Life Science segment increased 7%, with revenues from molecular component sales increasing 11% +over fiscal 2013 and revenues from immunoassay component sales increasing 5%. Life Science segment revenues increased 4% in fiscal 2013, with revenues from molecular component sales increasing 10% over fiscal 2012 and revenues from immunoassay +component sales decreasing 1%. Our molecular component business continues to benefit from new product launches and advancements – most notably SensiFAST™ and MyTaq™ PCR components. +- 31 - +Table of Contents +Diagnostics Revenue Overview- By Disease Family +Revenues from our focus families ( C. difficile , foodborne and H. pylori ) comprised 61%, 62% and 62% of our Diagnostics segment’s +revenues during fiscal 2014, 2013 and 2012, respectively. Following is a discussion of the revenues generated by each product family: +C. +difficile Products +During fiscal 2014, revenues for our C. difficile product family decreased 12% to $35,000. This followed growth +of 8% in fiscal 2013. Revenues for our illumi gene product decreased 6%, and expectedly, revenues for our C. difficile immunoassay products continued to significantly decline – 27% compared to fiscal 2013, as +much of this testing moves to molecular platforms. The C. difficile market has become highly competitive, with over 10 suppliers in the United States. Certain of these suppliers choose to compete solely on price. We believe that two factors +will help us respond to these challenging market conditions. First, our marketing programs emphasize that we are the only company that can offer a full range of high performing, FDA cleared, C. difficile testing formats, including toxin, GDH +and molecular tests. Second, our illumi gene molecular platform, with its expanding menu, requires no expensive equipment purchase or maintenance contract, which we believe makes it an attractive and affordable option for +any size hospital. +Foodborne Products +Revenues for our foodborne products (Enterohemorrhagic E. coli (EHEC) and Campylobacter ), all of which are immunoassay products, totaled +$23,000 during fiscal 2014, a 3% decrease from fiscal 2013. During fiscal 2013, this product line experienced 15% growth in revenues over the previous year. We continue to be disappointed in the results for the product family and are continuing to +re-emphasize the benefits of increased sensitivity and faster turnaround time versus culture methods in our marketing programs. While historically the primary competition for our foodborne products has been laboratory culture methods, during 2012 +one of our competitors cleared through the FDA a shiga toxin test that competes with our EHEC test. We believe that our test offers better workflow, less hands-on time and quicker results, in addition to being fully compliant with CDC-recommended +testing methods. +H. pylori Products +During fiscal 2014, revenues from our H. pylori products, all of which are immunoassay products, increased 7% to $28,000, which followed an 11% +increase during fiscal 2013. This increase continues to reflect the benefits of our partnerships with managed care companies in promoting the health and economic benefits of a test and treat strategy, and the ongoing effects of such strategy moving +physician behavior away from serology-based testing toward direct antigen testing. A significant amount of the H. pylori product revenues are from sales to reference labs, whose buying patterns may not be consistent period to period. +- 32 - +Table of Contents +Respiratory Products +Total respiratory revenues from our Diagnostics segment decreased 5% to $17,000 during fiscal 2014, following a 17% increase in the revenues from such products +in fiscal 2013. Lower sales of influenza products contributed to the current year decline in revenues. Partially offsetting the impact of lower influenza product revenues was growth in our illumi gene Group A Strep, +illumi gene Mycoplasma and illumi gene Pertussis products. +Foreign Currency +During fiscal 2014, currency exchange had an approximate $850 favorable impact on revenues; $600 within the Diagnostics segment and $250 within the Life +Science segment. This compares to currency exchange rates having a negligible impact on revenues in fiscal 2013; $150 favorable within the Diagnostics segment and $150 unfavorable in the Life Science segment. +Significant Customers +Two U.S. distributors +accounted for 36%, 42% and 41% of our Diagnostics segment’s total revenues for fiscal 2014, 2013 and 2012, respectively. These revenues represented 27%, 32% and 31% of consolidated revenues for fiscal 2014, 2013 and 2012, respectively. +Within our Life Science segment, two diagnostic manufacturing customers accounted for 16%, 17% and 19% of the segment’s total revenues for fiscal 2014, +2013 and 2012, respectively. These revenues represented 4%, 4% and 5% of our consolidated revenues for fiscal 2014, 2013 and 2012, respectively. +Medical Device Tax +On January 1, 2013, the +medical device tax established as part of the U.S. health care reform legislation became effective, and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2014 and 2013, the Company recorded +approximately $1,750 and $1,300, respectively, of medical device tax expense, which is reflected as a component of cost of sales in the accompanying Consolidated Statements of Operations. +Gross Profit : +2014 +2013 +2012 +2014 vs. +2013 +Inc (Dec) +2013 vs. +2012 +Inc (Dec) +Gross Profit +$ +117,243 +$ +121,044 +$ +109,048 +(3 +)% +11 +% +Gross Profit Margin +62 +% +64 +% +63 +% +-2 points ++1 point +The overall gross profit margin decrease during fiscal 2014 primarily results from the combined effects of (i) mix of +revenues from the Company’s segments; (ii) mix of products sold; (iii) declines in pricing on selected products; (iv) unfavorable manufacturing facility overhead absorption; and (v) the medical device tax, which did +- 33 - +Table of Contents +not exist during the first quarter of fiscal 2013. The overall improvement in the gross profit margin from fiscal 2012 to fiscal 2013 reflects the combined effects of (i) mix of sales from +the Company’s segments; (ii) lower overall cost structure from the consolidation of our Life Science immunoassay component manufacturing facilities; and (iii) mix of products sold. +Our overall operations consist of the sale of diagnostic test kits for various disease states and in alternative test formats, as well as bioresearch +reagents, bulk antigens and antibodies, PCR/qPCR reagents, nucleotides, competent cells, proficiency panels, contract research and development services, and contract manufacturing services. Product revenue mix shifts, in the normal course of +business, can cause the consolidated gross profit margin to fluctuate by several points. +Operating Expenses : +Research & +Development +Selling & +Marketing +General & +Administrative +Other +Total +Operating +Expenses +2012 Expenses +$ +10,275 +$ +22,092 +$ +26,372 +$ +1,013 +$ +59,752 +% of Revenues +6 +% +13 +% +15 +% +1 +% +35 +% +Fiscal 2013 Increases (Decreases): +Diagnostics +324 +572 +3,006 +— +3,902 +Life Science +188 +(240 +) +1,141 +(1,013 +) +76 +2013 Expenses +$ +10,787 +$ +22,424 +$ +30,519 +$ +— +$ +63,730 +% of Revenues +6 +% +12 +% +16 +% +— +34 +% +% Increase (Decrease) +5 +% +2 +% +16 +% +(100 +%) +7 +% +Fiscal 2014 Increases (Decreases): +Diagnostics +1,701 +1,289 +(2,036 +) +— +954 +Life Science +64 +1,197 +(1,094 +) +— +167 +2014 Expenses +$ +12,552 +$ +24,910 +$ +27,389 +$ +— +$ +64,851 +% of Revenues +7 +% +13 +% +15 +% +— +34 +% +% Increase (Decrease) +16 +% +11 +% +(10 +%) +— +2 +% +Overall, total operating expenses increased during both fiscal 2014 and fiscal 2013 relative to the immediately preceding +fiscal year, while remaining relatively consistent as a percentage of consolidated revenues. The fiscal 2014 increase results in large part from the combined net effects of our (i) ongoing efforts to control spending in each of our segments, +while investing the necessary resources in our strategic areas of growth, including increased investment in Research & Development for our molecular platform products and increased investment in Sales and Marketing personnel and programs; +and (ii) decreased incentive compensation compared to fiscal 2013 in light of the decline in corporate-wide operating profits. +During fiscal 2013, +the increase in operating expenses resulted in large part from the combined net effects of our (i) fiscal 2013 efforts to control spending in each of our segments while investing the necessary resources in our +- 34 - +Table of Contents +strategic areas of growth, including increased investment in Research & Development for our molecular platform products; (ii) increased sales personnel costs in Europe in connection +with filling open positions and upgrading talent; (iii) increased incentive compensation compared to fiscal 2012 based upon improved operating results; and (iv) costs incurred in connection with the consolidation of our Saco, Maine +operations into our Memphis, Tennessee location during fiscal 2012 of approximately $1,013. +Operating expenses for the Diagnostics segment increased $954 +for fiscal 2014 compared to fiscal 2013, and increased $3,902 for fiscal 2013 compared to fiscal 2012. These overall increases result largely from the combined effects of (i) currency exchange rates (increases of $200 and $50 for fiscal 2014 +and 2013, respectively); and (ii) the following: +Fiscal 2014 +Research & Development +Overall increase in spending on new product development activities, related primarily to the previously noted products for our +illumi gene molecular platform, as well as immunoassay products in development. +Selling & Marketing +Addition of field sales force and other personnel, including the filling of open territorial positions, resulting in an approximate $900 +increase in personnel-related expenses, along with increased product sample expense of approximately $300. +General & +Administrative +A decrease in bonus expense as a result of the previously noted decline in corporate-wide operating profits, partially +offset by an approximate $1,100 increase in stock-based compensation including the previously noted $429 of stock-based compensation expense related to the accelerated vesting of certain stock-based awards held by our Executive Chairman at the time +of his death in the fourth quarter of fiscal 2014 and other less significant general operating expense increases. +Fiscal 2013 +General & Administrative +Improved corporate-wide operating profits, resulting in increased bonus expense of approximately $3,100, along with an approximate $500 +increase in stock-based compensation during fiscal 2013. +Operating expenses for the Life Science segment increased $167 for fiscal 2014 compared to +fiscal 2013, and increased $76 for fiscal 2013 compared to fiscal 2012. The 2014 activity reflects in large part the net effects of (i) currency exchange rates (increase of $150 and decrease of $100 for fiscal 2014 and 2013, respectively); +(ii) ongoing increased sales and marketing investments; and (iii) decreased bonus expenses resulting from the +- 35 - +Table of Contents +decline in corporate-wide operating profits. The increase in 2013 primarily results from the combined effects of increased bonus expenses, investments in Bioline infrastructure and the lack of +Maine-Tennessee facility consolidation costs, which existed in fiscal 2012. +The amount of stock-based compensation expense reported for fiscal 2014, 2013 +and 2012 was $3,557, $2,502 and $1,987, respectively. During fiscal 2012, we granted restricted share units and options to certain executive management employees to reward them for meeting Company revenue targets in advance of planned expectations. +These awards can only be earned if specified cumulative revenue thresholds are achieved, with the three measurement dates for ratably earning one-third of the grant being (i) the 21-month period ended June 30, 2013; (ii) the 33-month +period ended June 30, 2014; and (iii) the 45-month period ending June 30, 2015. To date, with the exception of the final tranche of these awards being held by our Executive Chairman at the time of his death in the fourth quarter of +fiscal 2014, no expense has been recognized for these restricted share units and options, and as a result of the cumulative threshold for both the 21-month period ended June 30, 2013 and the 33-month period ended June 30, 2014 not being +met, two-thirds of the restricted share units and options granted have been cancelled. +During fiscal 2012 through fiscal 2014, we granted restricted +share units to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a +specified earnings target for each respective fiscal year. Although dividend equivalents were paid on these units throughout each of the respective fiscal years, because Meridian’s net earnings did not reach the minimum levels in any of these +three fiscal years, the performance-based awards were not earned and no stock-based compensation was recorded for the performance-based awards, except for those performance-based restricted share units being held by our Executive Chairman at the +time of his death in the fourth quarter of fiscal 2014. +Operating Income +Operating income decreased 9% and increased 16% in fiscal 2014 and 2013, respectively, as a result of the factors discussed above. +Income Taxes +The effective rate for income taxes has +remained relatively stable at 33%, 34% and 33% for fiscal 2014, 2013 and 2012, respectively. These rates reflect the net effects of various items, such as (i) the release of certain reserves for uncertain tax positions due to the passage of the +relevant statutes of limitations; (ii) the effect of adjusting, upon filing of the tax returns, the previously estimated permanent differences between income for financial reporting purposes and for tax purposes; and (iii) the net tax +benefit on dividends from a foreign-based subsidiary. +- 36 - +Table of Contents +In September 2013, the Internal Revenue Service issued Treasury Decision 9636, which enacted final tax +regulations regarding the capitalization and expensing of amounts paid to acquire, produce, or improve tangible property. The regulations also include guidance regarding the retirement of depreciable property. The regulations are required to be +effective in taxable years beginning on or after January 1, 2014, although taxpayers may choose to apply them in taxable years beginning on or after January 1, 2012. Our adoption of these regulations on October 1, 2014 did not have a +significant impact on the Company’s consolidated results of operations, cash flows or financial position. +Impact of Inflation +To the extent feasible, we have consistently followed the practice of adjusting our prices to reflect the impact of inflation on salaries and fringe benefits +for employees and the cost of purchased materials and services. Inflation and changing prices did not have a material adverse impact on our gross margin, revenues or operating income in fiscal 2014, 2013 or 2012. +Liquidity and Capital Resources : +Liquidity +Our cash flow and financing requirements are determined by analyses of operating and capital spending budgets, consideration of acquisition plans, +and consideration of common share dividends. We have historically maintained a credit facility to augment working capital requirements and to respond quickly to acquisition opportunities. Our investment portfolio presently consists of overnight +repurchase agreements. +We have an investment policy that guides the holdings of our investment portfolio. Our objectives in managing the investment +portfolio are to (i) preserve capital; (ii) provide sufficient liquidity to meet working capital requirements and fund strategic objectives such as acquisitions; and (iii) capture a market rate of return commensurate with market +conditions and our policy’s investment eligibility criteria. As we look forward, we will continue to manage the holdings of our investment portfolio with preservation of capital being the primary objective. +We do not expect current conditions in the financial markets, or overall economic conditions, to have a significant impact on our liquidity needs, financial +condition, or results of operations, although no assurances can be made in this regard. We intend to continue to fund our working capital requirements and dividends from current cash flows from operating activities and cash on hand. If needed, we +also have an additional source of liquidity through our $30,000 bank credit facility. Approximately $2,700 of our accounts receivable at September 30, 2014 is due from Italian hospital customers whose funding ultimately comes from the Italian +government, which is down from approximately $3,500 at September 30, 2013. Our liquidity needs may change if overall economic conditions worsen and/or liquidity and credit within the financial markets remains tight for an extended period of +time, and such conditions impact the collectibility of our customer accounts receivable or impact credit terms with our vendors, or disrupt the supply of raw materials and services. +- 37 - +Table of Contents +Fluctuations in overall stock market valuations may raise questions as to the potential impairment of goodwill +and other long-lived assets. Our annual goodwill impairment review takes place as of June 30 th each year. There have been no impairments from these annual reviews. As of September 30, +2014, our stock price was $17.69 per share, compared to our book value per share of $3.87 as of September 30, 2014. This relationship, stock price trading at a 4.6x multiple of book value, is an indicator that the fluctuation in overall stock +market valuations and its impact on our stock price has not been a triggering event for impairment of our goodwill and other long-lived assets. +During +fiscal 2014, our overall cash position decreased by approximately $1,000 to $43,000 at September 30, 2014. The primary contributors to this decrease were the net effects of (i) our 9% decrease in net earnings; (ii) our increase in +capital expenditures; and (iii) our payment of approximately $33,000 of cash dividends. +Net cash flows from operating activities and cash on hand +are anticipated to be adequate to fund working capital requirements, capital expenditures and dividends during the next twelve months. During fiscal 2014, the per share amount of our cash dividend paid represented 95% of our diluted earnings per +share, exceeding our long-standing policy of establishing a cash dividend payout ratio between 75% and 85% of diluted earnings per share. Despite there being certain individual fiscal years in which our payout ratio has fallen outside of this policy +range, since adopting this policy in November 2002, our cumulative cash dividend payout has approximated 84% of cumulative net earnings during this timeframe. +Capital Resources +We have a $30,000 credit +facility with a commercial bank which expires September 15, 2015. As of November 24, 2014, there were no borrowings outstanding on this facility and we had 100% borrowing capacity available to us. We have had no borrowings outstanding +under this facility during fiscal 2014, 2013 or 2012. +Our capital expenditures are estimated to range between approximately $4,000 to $5,000 for fiscal +2015, with the actual amount depending upon actual operating results and the phasing of certain projects. Such expenditures may be funded with cash and equivalents on hand, operating cash flows, and/or availability under the $30,000 credit facility +discussed above. +- 38 - +Table of Contents +Known Contractual Obligations : +Known contractual obligations and their related due dates were as follows as of September 30, 2014: +Total +Less than +1 Year +1-3 Years +4-5 Years +More than +5 Years +Operating leases (1) +$ +4,994 +$ +1,661 +$ +2,911 +$ +422 +$ +— +Purchase obligations (2) +9,642 +9,557 +67 +18 +— +Uncertain income tax positions liability and interest (3) +372 +372 +— +— +— +Total +$ +15,008 +$ +11,590 +$ +2,978 +$ +440 +$ +— +(1) +Meridian and its subsidiaries are lessees of (i) office and warehouse buildings in Ohio, Massachusetts, Florida, Australia, Belgium, France, Holland, Germany, Singapore, China and the U.K.; (ii) automobiles +for use by the diagnostic direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile machines and copier machines across all business units, under operating lease agreements that expire at various dates. +(2) +Meridian’s purchase obligations are primarily outstanding purchase orders for inventory and service items. These contractual commitments are not in excess of expected production requirements over the next twelve +months. +(3) +As of September 30, 2014, our liabilities for uncertain tax positions and related interest and penalties were $316 and $56, respectively. Due to inherent uncertainties in the timing of settlement of tax positions, +we are unable to estimate the timing of the effective settlement of these obligations. +Other Commitments and Off-Balance Sheet +Arrangements : +License Agreements +Meridian has entered into various license agreements that require payment of royalties based on a specified percentage of sales of related products (1% to +14%). Meridian expects that payments under these agreements will amount to approximately $3,000 in fiscal 2015. These royalty payments primarily relate to the Diagnostics segment. +Off-Balance Sheet Arrangements +Except for the +operating lease arrangements noted above, we have no off-balance sheet arrangements. +Market Risk Exposure: +Foreign Currency Risk +We have market risk exposure +related to foreign currency transactions from our operations outside the United States, as well as certain suppliers to our domestic businesses located outside the United States. The foreign currencies where we have market risk exposure are the +Australian dollar, the British pound, the Euro, and the Singapore dollar. Assessing foreign currency exposures is a component of our overall ongoing risk management process, with such currency risks managed as we believe appropriate. +- 39 - +Table of Contents +Concentration of Customers/Products Risk +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 36% of the segment’s total revenues or 27% of consolidated +revenues for fiscal 2014. Our C. difficile, foodborne and H. pylori product families accounted for 61% of our Diagnostics segment’s third-party revenues during fiscal 2014, and 46% of our fiscal 2014 consolidated revenues. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two diagnostics manufacturing customers were 16% of the +segment’s total revenues for fiscal 2014 or 4% of our fiscal 2014 consolidated revenues. Our Life Science segment has four other significant customers who purchase antigens, antibodies and reagents, which together comprised 8% of the +segment’s total revenues for fiscal 2014. +Critical Accounting Policies : +The consolidated financial statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally +accepted in the United States. Such accounting principles require management to make judgments about estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Management believes +that the following accounting policies are critical to understanding the accompanying consolidated financial statements because the application of such polices requires the use of significant estimates and assumptions and the carrying values of +related assets and liabilities are material. +Revenue Recognition +Our revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue for the Diagnostics segment is reduced at +the date of sale for product price adjustments due certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, estimates of +inventories of certain of our products held by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. +Revenue for our Diagnostics segment includes revenue for our illumi gene molecular test system. This system includes an instrument, +instrument accessories and test kits. In markets where the test system is sold via multiple deliverable arrangements (i.e., the United States, Australia, Belgium, France, Holland and Italy), the cost of the instrument and instrument accessories +is deferred upon placement at a customer and amortized on a straight-line basis into cost of sales over the expected utilization period, generally three years. +- 40 - +Table of Contents +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The significant +deliverables are an instrument, instrument accessories (e.g., printer) and test kits. An instrument and instrument accessories are delivered to the customer prior to the start of the customer utilization period, in order to accommodate customer +set-up and installation. There is de minimis consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are not a separate unit of accounting because such +equipment can only be used to process and read the results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test result), and therefore the instrument and +instrument accessories do not have standalone value to the customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the customer over the utilization period of +the instrument, which we estimate has a useful life of three years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue for the sale of test kits is recognized +upon shipment and transfer of title to the customers. +In markets where the test system is not sold via multiple deliverable arrangements (i.e., countries +other than the United States, Australia, Belgium, France, Holland and Italy), the cost of the instrument and instrument accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of +instruments and instrument accessories and test kits is recognized upon shipment and transfer of title to the customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory +the instruments, instrument accessories and test kits for resale to end-users. +Our products are generally not subject to a customer right of return +except for product recall events under the rules and regulations of the Food and Drug Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a loss +was probable and estimable. +Life Science revenue for contract services may come from research and development services or manufacturing services, +including process development work, or a combination of both. Revenue is recognized based on each of the deliverables in a given arrangement having distinct and separate customer pricing. Depending on the nature of the arrangement, revenue is +recognized as services are performed and billed, upon completion and acceptance by the customer, or upon delivery of product and acceptance by the customer. +Inventories +Our inventories are carried at the +lower of cost or market. Cost is determined on a first-in, first-out (FIFO). We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and other identified exposures. +We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and market conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the +period known. Such adjustments would negatively affect gross profit margin and overall results of operations. +- 41 - +Table of Contents +Intangible Assets +Our intangible assets include identifiable intangibles and goodwill. Identifiable intangibles include customer lists, supply agreements, manufacturing +technologies, patents, licenses and trade names. All of Meridian’s identifiable intangibles have finite lives. +Goodwill is subject to an annual +impairment review (or more frequently if impairment indicators arise). There have been no impairments from these analyses. +Identifiable intangibles with +finite lives are reviewed for impairment when events or circumstances indicate that such assets may not be recoverable at their current carrying value. Whether an event or circumstance triggers impairment is determined by comparing an estimate of +the asset’s undiscounted future cash flows to its carrying value. If impairment has occurred, it is measured by a fair-value based test. There were no events or circumstances in fiscal 2014, 2013 or 2012 indicating that the carrying value of +such assets may not be recoverable. +Our ability to recover intangible assets, both identifiable intangibles and goodwill, is dependent upon the future +cash flows of the related acquired businesses and assets. We are required to make judgments and assumptions regarding future cash flows, including sales levels, gross profit margins, operating expense levels, working capital levels, and capital +expenditures. With respect to identifiable intangibles, we also make judgments and assumptions regarding useful lives. +We consider the following factors +in evaluating events and circumstances for possible impairment: (i) significant under-performance relative to historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products +(related to specific identifiable intangibles); (iv) changes in overall business strategies; and (v) other factors. +If actual cash flows +decrease, this could trigger impairment of intangible assets and other long-lived assets. If impairment were to occur, this would negatively affect overall results of operations. +Income Taxes +Our provision for income taxes +includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting purposes and income for tax purposes. We prepare estimates of permanent and +temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, typically occurring in the third and fourth quarters of the current fiscal +year for the preceding fiscal year’s estimates. +- 42 - +Table of Contents +Our deferred tax assets include net operating loss carryforwards in foreign jurisdictions. The realization of tax +benefits related to net operating loss carryforwards is dependent upon the generation of future taxable income in the applicable jurisdictions. We assess the level of deferred tax asset valuation allowance needed, if any, by taking into +consideration historical and future projected operating results, future reversals of taxable temporary differences, as well as tax planning strategies. The amount of net deferred tax assets considered realizable could be reduced in future years if +estimates of future taxable income during the carryforward period are reduced. +Undistributed earnings in our non-U.S. subsidiaries are considered by us +to be permanently re-invested in such subsidiaries. Consequently, U.S. deferred tax liabilities on such earnings have not been recorded. +From time to +time, our tax returns in federal, state and foreign jurisdictions are examined by the applicable tax authorities. To the extent that adjustments result from the completion of these examinations or the lapsing of statutes of limitation, they will +affect tax liabilities in the period known. We believe that the results of any tax authority examinations would not have a significant adverse impact on our financial condition or results of operations. +In September 2013, the Internal Revenue Service issued Treasury Decision 9636, which enacted final tax regulations regarding the capitalization and expensing +of amounts paid to acquire, produce, or improve tangible property. The regulations also include guidance regarding the retirement of depreciable property. The regulations are required to be effective in taxable years beginning on or after +January 1, 2014, although taxpayers may choose to apply them in taxable years beginning on or after January 1, 2012. The Company’s adoption of these regulations on October 1, 2014 did not have a significant impact on the +Company’s consolidated results of operations, cash flows or financial position. +Recent Accounting Pronouncements : +In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entit y, +which includes amendments that change the requirements for reporting discontinued operations and requires additional disclosures about discontinued operations. Under the new guidance, only disposals representing a strategic shift in operations +should be presented as discontinued operations. This guidance will be effective for the Company beginning October 1, 2015, and we do not expect its adoption to have a significant impact on the Company’s consolidated results of operations, +cash flow or financial position. +- 43 - +Table of Contents +In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which +supersedes and replaces nearly all currently-existing U.S. GAAP revenue recognition guidance including related disclosure requirements. This guidance will be effective for the Company beginning October 1, 2017. The Company has not yet completed +its assessment of the impact that adoption of this guidance will have on its financial statements. +In August 2014, the FASB issued ASU 2014-15, +Presentation of Financial Statements — Going Concern (Subtopic 205-40), which addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going +concern and to provide related footnote disclosures. The guidance sets forth that management’s evaluation should be based on relevant conditions and events that are known and reasonably knowable at the date that the financial statements are +issued. This guidance will be effective for the Company beginning October 1, 2017. We do not expect to early adopt this guidance nor expect its adoption to have a significant impact on the Company’s consolidated results of operations, cash +flow or financial position. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +See Market Risk Exposure and Capital Resources under Item 7 above. +- 44 - +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements +Management’s Report on Internal Control over Financial Reporting +46 +Report of Independent Registered Public Accounting Firm +47 +Consolidated Statements of Operations for the years ended September 30, 2014, 2013 and 2012 +49 +Consolidated Statements of Comprehensive Income for the years ended September 30, 2014, 2013 and +2012 +50 +Consolidated Statements of Cash Flows for the years ended September 30, 2014, 2013 and 2012 +51 +Consolidated Balance Sheets as of September 30, 2014 and 2013 +52 +Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2014, 2013 and +2012 +54 +Notes to Consolidated Financial Statements +55 +Schedule No. II – Valuation and Qualifying Accounts for the years ended September +30, 2014, 2013 and 2012 +79 +All other supplemental schedules are omitted due to the absence of conditions under which they are required or because the +information is shown in the Consolidated Financial Statements or Notes thereto. +- 45 - +Table of Contents +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule +13a-15(f). +The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and +(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial +Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria in the 1992 Internal Control – Integrated Framework, issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Based on management’s evaluation and those criteria, the Company concluded that its system of internal control over financial reporting was effective as of September 30, 2014. +The Company’s independent registered public accounting firm has issued an attestation report on the registrant’s internal control over financial +reporting. +/s/ John A. Kraeutler +/s/ Melissa A. Lueke +John A. Kraeutler +Melissa A. Lueke +Chief Executive Officer +Executive Vice President and +December 1, 2014 +Chief Financial Officer +December 1, 2014 +- 46 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +We have audited the accompanying consolidated balance sheets of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the +“Company”) as of September 30, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, +2014. Our audits of the basic consolidated financial statements included the financial statement schedule listed in the index and appearing under Schedule No. II. We also have audited the Company’s internal control over financial reporting as +of September 30, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is +responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in +the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control +over financial reporting based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight +Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial +reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and +significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing +the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the +circumstances. We believe that our audits provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the +company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company +are +- 47 - +Table of Contents +being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized +acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent +limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in +conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the consolidated financial +statements referred to above present fairly, in all material respects, the financial position of Meridian Bioscience, Inc. and subsidiaries as of September 30, 2014 and 2013, and the results of their operations and their cash flows for each of +the three years in the period ended September 30, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to +the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also in our opinion, the Company maintained, in all material respects, effective internal control over +financial reporting as of September 30, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO. +/s/ GRANT THORNTON LLP +Cincinnati, Ohio +December 1, 2014 +- 48 - +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2014 +2013 +2012 +Net Revenues +$ +188,832 +$ +188,686 +$ +172,712 +Cost of Sales +71,589 +67,642 +63,664 +Gross Profit +117,243 +121,044 +109,048 +Operating Expenses: +Research and development +12,552 +10,787 +10,275 +Selling and marketing +24,910 +22,424 +22,092 +General and administrative +27,389 +30,519 +26,372 +Plant consolidation costs +— +— +1,013 +Total operating expenses +64,851 +63,730 +59,752 +Operating Income +52,392 +57,314 +49,296 +Other Income: +Interest income +25 +44 +42 +Other, net +(309 +) +4 +378 +Total other income +(284 +) +48 +420 +Earnings Before Income Taxes +52,108 +57,362 +49,716 +Income Tax Provision +17,365 +19,330 +16,345 +Net Earnings +$ +34,743 +$ +38,032 +$ +33,371 +Earnings Per Share Data: +Basic earnings per common share +$ +0.84 +$ +0.92 +$ +0.81 +Diluted earnings per common share +$ +0.83 +$ +0.91 +$ +0.80 +Common shares used for basic earnings per common share +41,455 +41,226 +41,080 +Effect of dilutive stock options and restricted shares and units +458 +669 +528 +Common shares used for diluted earnings per common share +41,913 +41,895 +41,608 +Dividends declared per common share +$ +0.79 +$ +0.76 +$ +0.76 +Anti-dilutive Securities: +Common share options and restricted shares and units +272 +254 +320 +The accompanying notes are an integral part of these consolidated financial statements. +- 49 - +Table of Contents +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2014 +2013 +2012 +Net Earnings +$ +34,743 +$ +38,032 +$ +33,371 +Foreign currency translation adjustment +(436 +) +650 +(354 +) +Comprehensive Income +$ +34,307 +$ +38,682 +$ +33,017 +The accompanying notes are an integral part of these consolidated financial statements. +- 50 - +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2014 +2013 +2012 +Cash Flows From Operating Activities +Net earnings +$ +34,743 +$ +38,032 +$ +33,371 +Non-cash items included in net earnings: +Depreciation of property, plant and equipment +3,523 +3,354 +3,490 +Amortization of intangible assets +2,039 +2,269 +2,165 +Amortization of deferred illumi gene instrument costs +1,702 +1,529 +942 +Stock-based compensation +3,557 +2,502 +1,987 +Deferred income taxes +(140 +) +(1,823 +) +(1,448 +) +Loss on disposition and write-down of fixed assets and other assets +6 +30 +359 +Change in current assets +(1,528 +) +(3,486 +) +1,234 +Change in current liabilities +(5,996 +) +2,669 +3,216 +Other, net +356 +(640 +) +(2,870 +) +Net cash provided by operating activities +38,262 +44,436 +42,446 +Cash Flows From Investing Activities +Purchases of property, plant and equipment +(5,306 +) +(3,234 +) +(3,530 +) +Proceeds from sale of assets +— +— +400 +Purchases of intangibles and other assets +(1,696 +) +(43 +) +(1,305 +) +Net cash used for investing activities +(7,002 +) +(3,277 +) +(4,435 +) +Cash Flows From Financing Activities +Dividends paid +(32,762 +) +(31,354 +) +(31,226 +) +Proceeds and tax benefits from exercises of stock options +1,009 +2,752 +552 +Net cash used for financing activities +(31,753 +) +(28,602 +) +(30,674 +) +Effect of Exchange Rate Changes on Cash and Equivalents +(742 +) +132 +630 +Net (Decrease) Increase in Cash and Equivalents +(1,235 +) +12,689 +7,967 +Cash and Equivalents at Beginning of Period +44,282 +31,593 +23,626 +Cash and Equivalents at End of Period +$ +43,047 +$ +44,282 +$ +31,593 +Supplemental Cash Flow Information +Cash paid for income taxes +$ +19,952 +$ +20,093 +$ +16,010 +The accompanying notes are an integral part of these consolidated financial statements. +- 51 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2014 +2013 +Assets +Current Assets: +Cash and equivalents +$ +43,047 +$ +44,282 +Accounts receivable, less allowances of $272 in 2014 and $233 in 2013 +23,232 +26,183 +Inventories +35,495 +34,835 +Prepaid expenses and other current assets +7,058 +4,643 +Deferred income taxes +3,916 +4,145 +Total current assets +112,748 +114,088 +Property, Plant and Equipment, at Cost: +Land +1,173 +1,183 +Buildings and improvements +29,146 +26,848 +Machinery, equipment and furniture +40,192 +38,502 +Construction in progress +652 +554 +Subtotal +71,163 +67,087 +Less: accumulated depreciation and amortization +43,553 +40,996 +Net property, plant and equipment +27,610 +26,091 +Other Assets: +Goodwill +23,193 +23,115 +Other intangible assets, net +7,813 +8,057 +Restricted cash +1,000 +1,000 +Deferred illumi gene instrument costs, net +2,740 +3,270 +Deferred income taxes +1,483 +823 +Other assets +342 +304 +Total other assets +36,571 +36,569 +Total assets +$ +176,929 +$ +176,748 +The accompanying notes are an integral part of these consolidated financial statements. +- 52 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2014 +2013 +Liabilities and Shareholders’ Equity +Current Liabilities: +Accounts payable +$ +4,966 +$ +5,592 +Accrued employee compensation costs +4,761 +9,847 +Other accrued expenses +3,149 +3,199 +Income taxes payable +859 +979 +Total current liabilities +13,735 +19,617 +Non-Current Liabilities +2,165 +2,086 +Commitments and Contingencies +Shareholders’ Equity: +Preferred stock, no par value, 1,000,000 shares authorized, none issued +— +— +Common shares, no par value, 71,000,000 shares authorized, 41,622,216 and 41,517,839 issued +— +— +Additional paid-in capital +111,851 +107,412 +Retained earnings +48,869 +46,888 +Accumulated other comprehensive income +309 +745 +Total shareholders’ equity +161,029 +155,045 +Total liabilities and shareholders’ equity +$ +176,929 +$ +176,748 +The accompanying notes are an integral part of these consolidated financial statements. +- 53 - +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (dollars and shares in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +Common +Shares +Issued +Additional +Paid-in +Capital +Retained +Earnings +Accum Other +Comp +Income +(Loss) +Total +Balance at September 30, 2011 +41,237 +$ +100,010 +$ +38,065 +$ +449 +$ +138,524 +Cash dividends paid—$0.76 per share +— +— +(31,226 +) +— +(31,226 +) +Exercise of stock options +47 +446 +— +— +446 +Issuance of restricted shares, net of forfeitures +(5 +) +— +— +— +— +Conversion of restricted stock units +5 +— +— +— +— +Stock compensation expense +— +1,987 +— +— +1,987 +Net earnings +— +— +33,371 +— +33,371 +Foreign currency translation adjustment +— +— +— +(354 +) +(354 +) +Balance at September 30, 2012 +41,284 +102,443 +40,210 +95 +142,748 +Cash dividends paid—$0.76 per share +— +— +(31,354 +) +— +(31,354 +) +Exercise of stock options +226 +2,564 +— +— +2,564 +Conversion of restricted stock units +8 +— +— +— +— +Stock compensation expense +— +2,405 +— +— +2,405 +Net earnings +— +— +38,032 +— +38,032 +Foreign currency translation adjustment +— +— +— +650 +650 +Balance at September 30, 2013 +41,518 +107,412 +46,888 +745 +155,045 +Cash dividends paid—$0.79 per share +— +— +(32,762 +) +— +(32,762 +) +Exercise of stock options +78 +882 +— +— +882 +Issuance of restricted shares, net of forfeitures +(1 +) +— +— +— +— +Conversion of restricted stock units +27 +— +— +— +— +Stock compensation expense +— +3,557 +— +— +3,557 +Net earnings +— +— +34,743 +— +34,743 +Foreign currency translation adjustment +— +— +— +(436 +) +(436 +) +Balance at September 30, 2014 +41,622 +$ +111,851 +$ +48,869 +$ +309 +$ +161,029 +The accompanying notes are an integral part of these consolidated financial statements. +- 54 - +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +Meridian Bioscience, Inc. and Subsidiaries +(dollars +and shares in thousands, except per share data) +(1) Summary of Significant Accounting Policies +(a) +Nature of Business - Meridian is a fully-integrated life science company whose principal businesses are (i) the development, manufacture and distribution of diagnostic test kits primarily for certain +gastrointestinal, viral, respiratory and parasitic infectious diseases; (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other +diagnostic manufacturers; and (iii) the contract development and manufacture of proteins and other biologicals for use by biopharmaceutical and biotechnology companies engaged in research for new drugs and vaccines. +(b) +Principles of Consolidation - The consolidated financial statements include the accounts of Meridian Bioscience, Inc. and its subsidiaries. All intercompany accounts and transactions have been eliminated. Unless +the context requires otherwise, references to “Meridian,” “we,” “us,” “our” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +(c) +Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of +assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. +(d) +Foreign Currency Translation - Assets and liabilities of foreign operations are translated using year-end exchange rates with gains or losses resulting from translation included as a separate component of +accumulated other comprehensive income or loss. Revenues and expenses are translated using exchange rates prevailing during the year. We also recognize foreign currency transaction gains and losses on certain assets and liabilities that are +denominated in the Australian dollar, British pound, Euro and Singapore dollar currencies. These gains and losses are included in other income and expense in the accompanying consolidated statements of operations. +(e) +Cash, Cash Equivalents and Investments - The primary objectives of our investment activities are to preserve capital and provide sufficient +liquidity to meet operating requirements and fund strategic initiatives such as acquisitions. We maintain a written investment policy that governs the management of our investments in fixed income securities. This policy, among other things, +provides that we may purchase only high credit-quality securities, that have short-term ratings of at least A-2, P-2 and F-2 or better, and long-term ratings of at least A, Baa1 and A or better, by +Standard & Poor’s, Moody’s and Fitch, +- 55 - +Table of Contents +respectively, at the time of purchase. We consider short-term investments with original maturities of 90 days or less to be cash equivalents, including overnight repurchase agreements and +institutional money market funds. At times our investments of cash and equivalents with various high credit quality financial institutions may be in excess of the Federal Deposit Insurance Corporation (FDIC) insurance limit. +Our investment portfolio includes the following components: +September 30, 2014 +September 30, 2013 +Cash and +Equivalents +Other +Cash and +Equivalents +Other +Overnight repurchase agreements +$ +26,407 +$ +— +$ +32,103 +$ +— +Cash on hand – +Restricted +— +1,000 +— +1,000 +Unrestricted +16,640 +— +12,179 +— +Total +$ +43,047 +$ +1,000 +$ +44,282 +$ +1,000 +(f) +Inventories - Inventories are stated at the lower of cost or market. Cost is determined on a first-in, first-out basis (FIFO). +illumi gene ® instruments are carried in inventory until customer placement, at which time they are transferred to deferred illumi gene instrument costs, +unless sold outright. +We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life +may expire before sale to customers, and other identified exposures. Such reserves were $2,942 and $2,499 at September 30, 2014 and 2013, respectively. We estimate these reserves based on assumptions about future demand and market conditions. +If actual demand and market conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. Such adjustments would negatively affect gross profit margin and overall +results of operations. +(g) +Property, Plant and Equipment - Property, plant and equipment are stated at cost. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed +from the accounts and the resulting gain or loss is reflected in earnings. Maintenance and repairs are expensed as incurred. Depreciation is computed on the straight-line method in amounts sufficient to write-off the cost over the estimated useful +lives, generally as follows: +Buildings and improvements—18 to 40 years +Machinery, equipment and furniture—3 to 10 years +Computer equipment and software—3 to 5 years +In connection with the fiscal 2012 consolidation of our Maine facility with our Tennessee facility, the carrying value of certain property, +plant and equipment, including the building, was determined to be impaired and a write-down of approximately $210 was recorded as a component of plant consolidation costs +- 56 - +Table of Contents +during the fiscal year ended September 30, 2012 in the accompanying consolidated statements of operations. The building and the property on which it sits have been written down to fair +value, less selling costs, as determined by an independent outside appraisal. +(h) +Intangible Assets - Goodwill is subject to an annual impairment review (or more frequently if impairment indicators arise) by first performing a qualitative assessment to determine whether it is more likely than +not that the fair value of a reporting unit is less than its carrying value. In the event that a reporting unit does not pass the qualitative assessment, the reporting unit’s carrying value is compared to its fair value, with fair value of the +reporting unit estimated using market and discounted cash flow approaches. Goodwill is considered impaired if the carrying value of the reporting unit exceeds its fair value. We perform our annual impairment review as of June 30, the end of our +third fiscal quarter. We have no intangible assets with indefinite lives other than goodwill. There have been no impairments from these analyses for fiscal 2014, 2013 or 2012. +The change in goodwill was an increase of $78 in fiscal 2014 and a decrease of $31 in fiscal 2013. Both years reflect the effect of the Life +Science segment’s Bioline Group and the currency translation adjustments thereon. +A summary of Meridian’s acquired intangible +assets subject to amortization, as of September 30, 2014 and 2013 is as follows. +2014 +2013 +As of September 30, +Gross +Carrying +Value +Accum. +Amort. +Gross +Carrying +Value +Accum. +Amort. +Manufacturing technologies, core products and cell lines +$ +11,685 +$ +10,568 +$ +11,676 +$ +10,097 +Trademarks, licenses and patents +6,463 +2,766 +4,748 +2,130 +Customer lists and supply agreements +12,378 +9,379 +12,353 +8,493 +$ +30,526 +$ +22,713 +$ +28,777 +$ +20,720 +During fiscal 2014, we acquired the remaining licensing rights related to patents that are part of our +illumi gene molecular technology for $1,638. These rights are being amortized over a weighted average period of approximately 8.5 years. +The actual aggregate amortization expense for these intangible assets for fiscal 2014, 2013 and 2012 was $2,039, $2,269 and $2,165, +respectively. The estimated aggregate amortization expense for these intangible assets for each of the five succeeding fiscal years is as follows: fiscal 2015—$1,737, fiscal 2016—$1,394, fiscal 2017—$1,158, fiscal 2018—$1,138 and +fiscal 2019—$1,097. +- 57 - +Table of Contents +Long-lived assets, excluding goodwill, are reviewed for impairment when events or circumstances +indicate that such assets may not be recoverable at their carrying value. Whether an event or circumstance triggers an impairment is determined by comparing an estimate of the asset’s future undiscounted cash flows to its carrying value. If +impairment has occurred, it is measured by a fair-value based test. +Our ability to recover the carrying value of our intangible assets, +both identifiable intangibles and goodwill, is dependent upon the future cash flows of the related acquired businesses and assets. We make judgments and assumptions regarding future cash flows, including sales levels, gross profit margins, operating +expense levels, working capital levels, and capital expenditures. With respect to identifiable intangibles and fixed assets, we also make judgments and assumptions regarding useful lives. +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant under-performance +relative to historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; and +(v) other factors. +If actual cash flows are less favorable than projections, this could trigger impairment of intangible assets and +other long-lived assets. If impairment were to occur, this would negatively affect overall results of operations. +(i) +Revenue Recognition and Accounts Receivable - Revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue for the Diagnostics segment is reduced at the date of +sale for product price adjustments due certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, estimates of inventories of +certain of our products held by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. Such accruals were $4,220 at September 30, 2014 and $3,866 at +September 30, 2013, and have been netted against accounts receivable. +Revenue for our Diagnostics segment includes +revenue for our illumi gene molecular test system. This system includes an instrument, instrument accessories and test kits. In markets where the test system is sold via multiple deliverable arrangements (i.e., the +United States, Australia, Belgium, France, Holland and Italy), the cost of the instrument and instrument accessories is deferred upon placement at a customer and amortized on a straight-line basis into cost of sales over the expected utilization +period, generally three years. +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The significant +deliverables are an instrument, instrument accessories (e.g., printer) and test kits. An instrument and +- 58 - +Table of Contents +instrument accessories are delivered to the customer prior to the start of the customer utilization period, in order to accommodate customer set-up and installation. There is de minimis +consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are not a separate unit of accounting because such equipment can only be used to process and read the +results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test result), and therefore the instrument and instrument accessories do not have standalone value to the +customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the customer over the utilization period of the instrument, which we estimate has a useful life of three +years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue for the sale of test kits is recognized upon shipment and transfer of title to the customers. +In markets where the test system is not sold via multiple deliverable arrangements (i.e., countries other than the United States, Australia, +Belgium, France, Holland and Italy), the cost of the instrument and instrument accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of instruments and instrument accessories and +test kits is recognized upon shipment and transfer of title to the customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory the instruments, instrument accessories and +test kits for resale to end-users. +Our products are generally not subject to a customer right of return except for product recall events +under the rules and regulations of the Food and Drug Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a loss was probable and estimable. +Life Science revenue for contract services may come from research and development services or manufacturing services, including process +development work, or a combination of both. Revenue is recognized based on each of the deliverables in a given arrangement having distinct and separate customer pricing. Depending on the nature of the arrangement, revenue is recognized as services +are performed and billed, upon completion and acceptance by the customer, or upon delivery of product and acceptance by the customer. +Trade accounts receivable are recorded in the accompanying consolidated balance sheets at invoiced amounts less provisions for distributor +price adjustments under local contracts and doubtful accounts. The allowance for doubtful accounts represents our estimate of probable credit losses and is based on historical write-off experience and known conditions that would likely lead to +non-payment. The allowance for doubtful accounts and related metrics, such as days’ sales outstanding, are reviewed monthly. Accounts with past due balances over 90 days are reviewed individually for collectibility. Customer invoices are +charged off against the allowance when we believe it is probable that the invoices will not be paid. +- 59 - +Table of Contents +(j) +Research and Development Costs - Research and development costs are charged to expense as incurred. Research and development costs include, among other things, salaries and wages for research scientists, +materials and supplies used in the development of new products, costs for development of instrumentation equipment, costs for clinical trials, and costs for facilities and equipment. +(k) +Income Taxes - The provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting +and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, typically +occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +We +account for uncertain tax positions using a benefit recognition model with a two-step approach: (i) a more-likely-than-not recognition criterion; and (ii) a measurement attribute that measures the position as the largest amount of tax +benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit is recorded. We recognize accrued interest +related to unrecognized tax benefits as a portion of our income tax provision in the consolidated statements of operations. See Note 4. +(l) +Stock-Based Compensation - We recognize compensation expense for all share-based awards made to employees, based upon the fair value of the share-based award on the date of the grant. See Note 5(b). +(m) +Comprehensive Income (Loss) - Comprehensive income (loss) represents the net change in shareholders’ equity during a period from sources other than transactions with shareholders. As reflected in the +accompanying consolidated statements of comprehensive income, our comprehensive income or loss is comprised of net earnings and foreign currency translation. +(n) +Shipping and Handling Costs - Shipping and handling costs invoiced to customers are included in net revenues. Costs to distribute products to customers, including freight costs, warehousing costs, and other +shipping and handling activities are included in cost of sales. +(o) +Non-Income Government-Assessed Taxes - We classify all non-income, government-assessed taxes (sales, use and value-added) collected from customers and remitted by us to appropriate revenue authorities, on a net +basis (excluded from net revenues) in the accompanying consolidated statements of operations. +- 60 - +Table of Contents +(p) +Recent Accounting Pronouncements - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which supersedes and replaces nearly all currently-existing U.S. GAAP revenue +recognition guidance including related disclosure requirements. This guidance will be effective for the Company beginning October 1, 2017. The Company has not yet completed its assessment of the impact that adoption of this guidance will have +on its financial statements. +(q) +Reclassifications - Certain reclassifications have been made to the prior fiscal year financial statements to conform to the current year presentation. Such reclassifications had no impact on net earnings or +shareholders’ equity. +(2) Inventories +Inventories are comprised of the following: +As of September 30, +2014 +2013 +Raw materials +$ +5,674 +$ +7,170 +Work-in-process +10,591 +8,585 +Finished goods— illumi gene instruments +1,710 +1,980 +Finished goods—kits and reagents +17,520 +17,100 +Total +$ +35,495 +$ +34,835 +(3) Bank Credit Arrangements +We have a $30,000 credit facility with a commercial bank, which expires in September 2015. This credit facility is collateralized by our +business assets, except for those of non-U.S. subsidiaries, which totaled approximately $147,000 at September 30, 2014. There were no borrowings outstanding on this credit facility at September 30, 2014 or September 30, 2013. +Available borrowings under this credit facility were $30,000 at September 30, 2014 and September 30, 2013. In connection with this bank credit facility, we are required to comply with financial covenants that limit the amount of debt +obligations and require a minimum amount of tangible net worth. We are in compliance with all covenants. We are also required to maintain a cash compensating balance with the bank in the amount of $1,000, pursuant to this bank credit facility and +are in compliance with this requirement. +- 61 - +Table of Contents +(4) Income Taxes +(a) +Earnings before income taxes, and the related provision for income taxes for the years ended September 30, 2014, 2013 and 2012 were as follows: +Year Ended September 30, +2014 +2013 +2012 +Domestic +$ +48,350 +$ +53,963 +$ +44,774 +Foreign +3,758 +3,399 +4,942 +Total earnings before income taxes +$ +52,108 +$ +57,362 +$ +49,716 +Provision (credit) for income taxes— +Federal— +Current +$ +15,021 +$ +18,311 +$ +15,077 +Temporary differences +Fixed asset basis differences and depreciation +108 +121 +2 +Intangible asset basis differences and amortization +(210 +) +(339 +) +(354 +) +Currently non-deductible expenses and reserves +50 +(425 +) +(397 +) +Stock-based compensation +59 +(282 +) +(599 +) +Tax credit carryforwards +225 +(717 +) +— +Other, net +66 +43 +74 +Subtotal +15,319 +16,712 +13,803 +State and local +1,762 +2,013 +1,521 +Foreign +284 +605 +1,021 +Total income tax provision +$ +17,365 +$ +19,330 +$ +16,345 +(b) +The following is a reconciliation between the statutory U.S. income tax rate and the effective rate derived by dividing the provision for income taxes by earnings before income taxes: +Year Ended September 30, +2014 +2013 +2012 +Computed income taxes at statutory rate +$ +18,238 +35.0 +% +$ +20,078 +35.0 +% +$ +17,398 +35.0 +% +Increase (decrease) in taxes resulting from— +State and local income taxes +1,061 +2.0 +1,270 +2.2 +994 +2.0 +Net benefit on foreign dividend +(274 +) +(0.5 +) +(84 +) +(0.2 +) +(373 +) +(0.8 +) +Foreign tax rate differences +(430 +) +(0.8 +) +(18 +) +— +(114 +) +(0.2 +) +Qualified domestic production incentives +(1,175 +) +(2.3 +) +(1,621 +) +(2.8 +) +(1,226 +) +(2.5 +) +Uncertain tax position activity +164 +0.3 +(80 +) +(0.1 +) +(71 +) +(0.1 +) +Other, net +(219 +) +(0.4 +) +(215 +) +(0.4 +) +(263 +) +(0.5 +) +$ +17,365 +33.3 +% +$ +19,330 +33.7 +% +$ +16,345 +32.9 +% +- 62 - +Table of Contents +(c) +The components of net deferred tax assets were as follows: +As of September 30, +2014 +2013 +Deferred tax assets— +Valuation reserves and non-deductible expenses +$ +1,984 +$ +1,784 +Stock compensation expense not deductible +3,328 +3,381 +Net operating loss carryforwards +536 +734 +Tax credit carryforwards +492 +717 +Inventory basis differences +1,340 +1,626 +Other +8 +33 +Subtotal +7,688 +8,275 +Less valuation allowance +— +(296 +) +Deferred tax assets +7,688 +7,979 +Deferred tax liabilities— +Fixed asset basis differences and depreciation +(951 +) +(862 +) +Intangible asset basis differences and amortization +(1,338 +) +(1,924 +) +Other +— +(225 +) +Deferred tax liabilities +(2,289 +) +(3,011 +) +Net deferred tax assets +$ +5,399 +$ +4,968 +For income tax purposes, we have tax benefits related to operating loss carryforwards in the countries of Australia and +Belgium, which have no expiration date. We have recorded deferred tax assets for these carryforwards totaling $536 and $734 at September 30, 2014 and September 30, 2013, respectively, excluding valuation allowances for Australia as of +September 30, 2013. For income tax purposes, we also have tax benefits related to tax credit carryforwards in the U.S., which expire in fiscal 2022. We have recorded deferred tax assets for these carryforwards totaling $492 and $717 at +September 30, 2014 and September 30, 2013, respectively. +The realization of deferred tax assets in foreign jurisdictions is dependent upon the +generation of future taxable income in these countries. We have considered the levels of currently anticipated pre-tax income in foreign jurisdictions in assessing the required level of the deferred tax asset valuation allowance. Taking into +consideration historical and current operating results, and other factors, we believe that it is more likely than not that the net deferred tax asset for foreign jurisdictions will be realized. The amount of the net deferred tax asset considered +realizable in foreign jurisdictions, however, could be reduced in future years if estimates of future taxable income during the carryforward period are reduced. +Undistributed earnings reinvested indefinitely in our non-U.S. operations were approximately $8,000 and $14,000 at September 30, 2014 and +September 30, 2013, respectively. U.S. deferred tax liabilities of approximately $1,300 and $1,000 on such earnings, after consideration of foreign tax credits, have not been recorded as of September 30, 2014 and September 30, 2013, +respectively. +As described in Note 1, we utilize a comprehensive model for the recognition, measurement, presentation and disclosure of uncertain tax +positions, assuming full knowledge of all relevant facts by the applicable tax authorities. The total amount of unrecognized tax benefits at September 30, 2014 and September 30, 2013 +- 63 - +Table of Contents +related to such positions was $372 and $208, respectively, of which the full amounts would favorably affect the effective tax rate if recognized. We recognize interest and penalties related to +uncertain tax positions as a component of our income tax provision. During fiscal 2014 we increased our tax provision by approximately $26 for such interest and penalties, while during fiscal 2013 they resulted in an approximate $72 decrease in our +tax provision. We had approximately $56 accrued for the payment of interest and penalties at September 30, 2014 compared to $30 accrued at September 30, 2013. The amount of our liability for uncertain tax positions expected to be paid or +settled in the next 12 months is uncertain. +A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: +2014 +2013 +Unrecognized income tax benefits beginning of year +$ +208 +$ +471 +Additions for tax positions related to the current year +11 +— +Additions for tax positions of prior years +153 +61 +Reductions for tax positions of prior years +— +(103 +) +Tax examination and other settlements +— +(183 +) +Expirations of statute of limitations +— +(38 +) +Unrecognized income tax benefits at end of year +$ +372 +$ +208 +We are subject to examination by the tax authorities in the U.S. (both federal and state) and the countries of Australia, +Belgium, England, France, Germany, Holland and Italy. In the U.S., open tax years are for fiscal 2011, fiscal 2012 and fiscal 2013, with the IRS having completed its examination of our federal return for fiscal 2011 and, therefore, leaving only the +states open for this year. In countries outside the U.S., open tax years generally range from fiscal 2009 and forward. However, in Australia and Belgium, the utilization of local net operating loss carryforwards extends the statute of limitations +for examination well into the foreseeable future. +(5) Employee Benefits +(a) +Savings and Investment Plan - We have a profit sharing and retirement savings plan covering substantially all full-time U.S. employees. Profit sharing contributions to the plan, which are discretionary, are +approved by the board of directors. The plan permits participants to contribute to the plan through salary reduction. Under terms of the plan, we match 50% of an employee’s contributions, up to a maximum match of 3% of eligible compensation. +Our discretionary and matching contributions to the plan amounted to approximately $1,542, $1,539 and $2,033, during fiscal 2014, 2013 and 2012, respectively. +(b) +Stock-Based Compensation Plans - During fiscal 2014, we had two active stock-based compensation plans, the 2004 Equity Compensation Plan, which became effective December 7, 2004, as amended (the “2004 +Plan”) and the 2012 Stock Incentive Plan, which became effective January 25, 2012 (the “2012 Plan”). In addition, we have an Employee Stock Purchase Plan (the “ESP Plan”), which became effective October 1, 1997. +Under the ESP Plan, we sell shares of stock to our full-time and part-time employees up to the number of shares equivalent to a 1% to 15% payroll deduction from an employee’s base salary plus an additional 5% dollar match of this deduction by +Meridian. +- 64 - +Table of Contents +Each of the 2004 Plan and 2012 Plan authorized the granting of new shares for options, restricted +shares or restricted share units for up to 3,000 shares, with the non-granted portion of the 2004 Plan permitted to be carried forward and added to the 2012 Plan authorized limit. As of September 30, 2014, we have granted 1,882 and 415 shares +under the 2004 Plan and 2012 Plan, respectively, thereby resulting in a remaining authorized limit of 3,703 shares. Options may be granted at exercise prices not less than 100% of the closing market value of the underlying common shares on the date +of grant and have maximum terms up to ten years. Vesting schedules for options, restricted shares and restricted share units are established at the time of grant and may be set based on future service periods, achievement of performance targets, or +a combination thereof. All options contain provisions restricting their transferability and limiting their exercise in the event of termination of employment or the disability or death of the optionee. We recognize compensation expense for all +share-based payments made to employees, based upon the fair value of the share-based payment on the date of the grant. +During fiscal 2012, +we granted approximately 210 restricted share units (with a weighted-average grant date fair value of $17.99 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total +on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings target for fiscal 2012. While dividend equivalents were paid on these units throughout fiscal 2012, the target for fiscal 2012 +was not met and the performance-based portion of the restricted share units granted during fiscal 2012 were cancelled. Additionally, during fiscal 2012, we granted approximately 110 restricted share units (with a grant date fair value of $17.57 per +share) and 1,035 options (with a weighted-average grant date fair value of $4.66 per option, as included in the options table below) to certain executive management employees to incentivize the achievement of Company revenue targets in advance of +planned expectations. These awards can only be earned if specified cumulative revenue thresholds are achieved, with the three measurement dates for ratably earning one-third of the grant being (i) the 21-month period ended June 30, 2013; +(ii) the 33-month period ended June 30, 2014; and (iii) the 45-month period ending June 30, 2015. As a result of the cumulative thresholds for the 21-month and 33-month periods ended +June 30, 2014 and June 30, 2013, respectively, not having been met, two-thirds of the restricted share units and options granted have been cancelled accordingly. +During fiscal 2013, we granted approximately 204 restricted share units (with a weighted-average grant date fair value of $19.38 per share) to +certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings +target for fiscal 2013. While dividend equivalents were paid on these units throughout fiscal 2013, the target for fiscal 2013 was not met and the performance-based portion of the restricted share units granted during fiscal 2013 have been +cancelled. +- 65 - +Table of Contents +Similar to previous years, during fiscal 2014, we granted approximately 270 restricted share +units (with a weighted-average grant date fair value of $24.82 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, +and the remaining half being subject to attainment of a specified earnings target for fiscal 2014. While dividend equivalents were paid on these units throughout fiscal 2014, the target for fiscal 2014 was not met and the performance-based portion +of the restricted share units granted during fiscal 2014 have been cancelled. +Giving effect to these grants, cancellations and certain +other activities for restricted shares and restricted share units throughout the years, including conversions to common shares, forfeitures, and new hire and employee promotion grants, approximately 400 restricted shares and restricted share units +remain outstanding as of September 30, 2014, with a weighted-average grant date fair value of $21.01 per share, a weighted-average remaining vesting period of 1.74 years and an aggregate intrinsic value of $7,071. The weighted-average grant +date fair value of the approximate 145 restricted share units that vested during fiscal 2014 was $22.04 per share. +The amount of +stock-based compensation expense reported was $3,557, $2,502 and $1,987 in fiscal 2014, 2013 and 2012, respectively. The fiscal 2014 expense is comprised of $486 related to stock options and $3,071 related to restricted shares and units; the fiscal +2013 expense is comprised of $336 related to stock options, $2,069 related to restricted shares and units, and $97 related to the granting of unrestricted common shares to two executive officers; and the fiscal 2012 expense is comprised of $426 +related to stock options and $1,561 related to restricted shares and units. The total income tax benefit recognized in the income statement for these stock-based compensation arrangements was $1,185, $850 and $588, for fiscal 2014, 2013 and 2012, +respectively. As of September 30, 2014, we expect future stock compensation expense for unvested options and unvested restricted stock and units to total $185 and $2,105, respectively, which will be recognized during fiscal years 2015 through +2018. +We recognize compensation expense only for the portion of shares that we expect to vest. As such, we apply estimated forfeiture +rates to our compensation expense calculations. These rates have been derived using historical forfeiture data, stratified by several employee groups. During fiscal 2014, 2013 and 2012, we recorded $108, $93 and $73, respectively, in stock +compensation expense to adjust estimated forfeiture rates to actual. +- 66 - +Table of Contents +We have elected to use the Black-Scholes option pricing model to determine grant-date fair value +for stock options, with the following assumptions: (i) expected share price volatility based on the average of Meridian’s historical volatility over the options’ expected lives and implied volatility based on the value of tradable +call options; (ii) expected life of options based on contractual lives, employees’ historical exercise behavior and employees’ historical post-vesting employment termination behavior; (iii) risk-free interest rates based on +treasury rates that correspond to the expected lives of the options; and (iv) dividend yield based on the expected yield on underlying Meridian common stock. +Year ended September 30, +2014 +2013 +2012 +Risk-free interest rates +1.8% +0.88% +1.24% +Dividend yield +3.5% +4.1% +3.42% +Life of option +6.29 yrs. +6.23 yrs. +6.22 yrs. +Share price volatility +33% +36 % +39% +Forfeitures (by employee group) +0%-14% +0%-10% +0%-10% +A summary of the status of our stock option plans at September 30, 2014 and changes during the year is +presented in the table and narrative below: +Options +Wtd Avg +Exercise +Price +Wtd Avg +Remaining +Life (Yrs) +Aggregate +Intrinsic +Value +Outstanding beginning of period +1,508 +$ +17.93 +Grants +70 +24.20 +Exercises +(78 +) +7.27 +Forfeitures +(13 +) +21.50 +Cancellations +(345 +) +17.57 +Outstanding end of period +1,142 +$ +19.11 +5.08 +$ +1,261 +Exercisable end of period +782 +$ +19.27 +3.97 +$ +1,219 +A summary of the status of our nonvested options as of September 30, 2014, and changes during the year +ended September 30, 2014, is presented below: +Options +Weighted- +Average +Grant Date +Fair Value +Nonvested beginning of period +787 +$ +4.66 +Granted +70 +5.48 +Vested +(144 +) +4.88 +Forfeitures +(8 +) +4.94 +Cancelled +(345 +) +4.66 +Nonvested end of period +360 +$ +4.78 +- 67 - +Table of Contents +The weighted average grant-date fair value of options granted was $5.48, $4.19 and $4.68 for +fiscal 2014, 2013 and 2012, respectively. The total intrinsic value of options exercised was $1,110, $2,483 and $452, for fiscal 2014, 2013 and 2012, respectively. The total grant-date fair value of options that vested during fiscal 2014, 2013 and +2012 was $701, $712 and $361, respectively. +Cash received from options exercised was $567, $2,258 and $431 for fiscal 2014, 2013 and 2012, +respectively. Tax benefits realized and recorded to additional paid-in capital from option exercises totaled $315, $306 and $15 for fiscal 2014, 2013 and 2012, respectively. +(6) Non-Current Liabilities +The Company and its Chairman and Chief Executive Officer are parties to an employment agreement and a supplemental benefit agreement, under +which we are obligated to provide certain post-retirement and insurance benefits. These obligations total $1,247 and $1,056 at September 30, 2014 and September 30, 2013, respectively. In addition, we are required by the governments of +certain of the foreign countries in which we operate to maintain a level of reserves for potential future severance indemnity. These reserves total $831 and $827 at September 30, 2014 and September 30, 2013, respectively. +(7) Reportable Segments and Major Concentration Data +Our reportable segments are Diagnostics and Life Science, with segmentation between the two determined based upon the nature of products and +the types of customers. The Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, and the sale and distribution of diagnostic test kits domestically and abroad. The Life Science segment consists of manufacturing operations in +Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically +and abroad. The Life Science segment also includes the contract development and manufacture of cGMP clinical grade proteins and other biologicals for use by biopharmaceutical and biotechnology companies engaged in research for new drugs and +vaccines. +Revenues from individual customers constituting 10% or more of consolidated net revenues are as follows: +Year Ended September 30, +2014 +2013 +2012 +Customer A +$ +28,278 +(15 +)% +$ +35,082 +(19 +)% +$ +32,771 +(19 +)% +Customer B +$ +22,729 +(12 +)% +$ +25,457 +(13 +)% +$ +19,903 +(12 +)% +Accounts receivable from these two Diagnostics distributor customers accounted for 15% and 17% of consolidated accounts +receivable at September 30, 2014 and September 30, 2013, respectively. In addition, approximately 14% of the consolidated accounts receivable balance at September 30, 2014 is largely dependent upon funds from the Italian government. +The Company’s international revenues totaled $57,051, $56,224, and $54,909 in fiscal years 2014, 2013 and 2012, respectively. Our diagnostic focus product families – C. difficile, +- 68 - +Table of Contents +foodborne and H. pylori – accounted for 46%, 47% and 47% of consolidated net revenues in fiscal 2014, 2013 and 2012, respectively. We currently sole-source from a U.S. +manufacturer the illumi pro -10 ™ instrument on which our illumi gene molecular testing platform operates. Additionally, two of our foodborne products sourced from another vendor +accounted for 14%, 14% and 13% of third-party revenues for our Diagnostics segment in fiscal 2014, 2013 and 2012, respectively. +Significant +revenue information by country for the Diagnostics and Life Science segments is as follows. Revenues are attributed to the geographic area based on the location to which the product is delivered. +Year Ended September 30, +2014 +2013 +2012 +United States +$ +112,917 +$ +114,935 +$ +99,998 +Italy +8,469 +7,427 +7,473 +Japan +2,097 +3,937 +3,922 +United Kingdom +1,942 +2,141 +2,441 +France +1,841 +1,936 +2,149 +Holland +1,613 +1,764 +1,818 +Canada +1,359 +1,248 +941 +Belgium +1,241 +1,285 +1,271 +Other countries +10,021 +9,956 +10,167 +Total Diagnostics +$ +141,500 +$ +144,629 +$ +130,180 +Year Ended September 30, +2014 +2013 +2012 +United States +$ +18,864 +$ +17,527 +$ +17,805 +Germany +7,232 +6,465 +4,872 +United Kingdom +5,647 +5,590 +5,251 +Australia +4,063 +3,454 +3,423 +France +1,633 +1,440 +1,282 +Other countries +9,893 +9,581 +9,899 +Total Life Science +$ +47,332 +$ +44,057 +$ +42,532 +Identifiable assets for our Italian distribution organization were $10,861 and $10,760 at September 30, 2014 and 2013, +respectively. At September 30, 2014, identifiable assets for the Bioline Group’s operations in the U.K., Germany and Australia totaled approximately $14,985, $7,713 and $4,171, respectively; and totaled $14,220, $7,965 and $4,239, +respectively, at September 30, 2013. +- 69 - +Table of Contents +Segment information for the years ended September 30, 2014, 2013 and 2012 is as follows: +Diagnostics +Life Science +Elim (1) +Total +Fiscal Year 2014— +Net revenues – +Third-party +$ +141,500 +$ +47,332 +$ +— +$ +188,832 +Inter-segment +432 +1,009 +(1,441 +) +— +Operating income +41,629 +10,861 +(98 +) +52,392 +Depreciation and amortization +4,283 +2,981 +— +7,264 +Capital expenditures +4,176 +1,130 +— +5,306 +Goodwill +1,250 +21,943 +— +23,193 +Other intangible assets +2,756 +5,057 +— +7,813 +Total assets +109,086 +67,790 +53 +176,929 +Fiscal Year 2013— +Net revenues – +Third-party +$ +144,629 +$ +44,057 +$ +— +$ +188,686 +Inter-segment +533 +1,223 +(1,756 +) +— +Operating income +46,735 +10,627 +(48 +) +57,314 +Depreciation and amortization +4,328 +2,824 +— +7,152 +Capital expenditures +2,031 +1,203 +— +3,234 +Goodwill +1,250 +21,865 +— +23,115 +Other intangible assets +1,561 +6,496 +— +8,057 +Total assets +111,719 +65,393 +(364 +) +176,748 +Fiscal Year 2012— +Net revenues – +Third-party +$ +130,180 +$ +42,532 +$ +— +$ +172,712 +Inter-segment +599 +1,097 +(1,696 +) +— +Operating income (2) +40,648 +8,473 +175 +49,296 +Depreciation and amortization +3,732 +2,865 +— +6,597 +Capital expenditures +2,341 +1,189 +— +3,530 +Goodwill +1,250 +21,896 +— +23,146 +Other intangible assets +2,239 +8,025 +— +10,264 +Total assets +96,620 +59,019 +5,742 +161,381 +(1) +Eliminations consist of intersegment transactions. +(2) +Life Science includes $1,013 related to consolidation of the Maine operations into the Tennessee facility. +- 70 - +Table of Contents +A reconciliation of segment operating expenses to consolidated earnings before income taxes for the years ended +September 30, 2014, 2013 and 2012 is as follows: +Year Ended September 30, +2014 +2013 +2012 +Segment operating income +$ +52,392 +$ +57,314 +$ +49,296 +Interest income +25 +44 +42 +Other, net +(309 +) +4 +378 +Consolidated earnings before income taxes +$ +52,108 +$ +57,362 +$ +49,716 +Transactions between segments are accounted for at established intercompany prices for internal and management purposes with +all intercompany amounts eliminated in consolidation. +(8) Commitments and Contingencies +(a) +Royalty Commitments - We have entered into various license agreements that require payment of royalties based on a specified percentage of the sales of licensed products (1% to 14%). These royalty expenses are +recognized on an as-earned basis and recorded in the year earned as a component of cost of sales. Annual royalty expenses associated with these agreements were approximately $3,482, $3,611 and $3,040, respectively, for the fiscal years ended +September 30, 2014, 2013 and 2012. +(b) +Purchase Commitments - Excluding the operating lease commitments reflected in Note 8 (c) below, we have purchase commitments primarily for inventory and service items as part of the normal course of +business. Commitments made under these obligations are $9,557, $67 and $18 for fiscal 2015, 2016 and 2017, respectively. No purchase commitments have been made beyond fiscal 2017. +(c) +Operating Lease Commitments - Meridian and its subsidiaries are lessees of (i) certain office and warehouse buildings in the U.S., Europe, Australia, Singapore and China; (ii) automobiles for use by the +direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile and copier machines across all business units, under operating lease agreements that expire at various dates. Amounts charged to expense under +operating leases were $1,951, $1,744 and $1,524 for fiscal 2014, 2013 and 2012, respectively. Operating lease commitments for each of the five succeeding fiscal years are as follows: fiscal 2015—$1,661, fiscal 2016—$1,389, fiscal +2017—$830, fiscal 2018—$692, and fiscal 2019—$422. +(d) +Litigation - We are a party to various litigation matters from time to time that we believe are in the normal course of business. The ultimate resolution of these matters is not expected to have a material +adverse effect on our financial position, results of operations or cash flows. +- 71 - +Table of Contents +(e) +Indemnifications - In conjunction with certain contracts and agreements, we provide routine indemnifications whose terms range in duration and in some circumstances are not explicitly defined. The maximum +obligation under some such indemnifications is not explicitly stated and, as a result of our having no history of paying such indemnifications, cannot be reasonably estimated. We have not made any payments for these indemnifications and no liability +is recorded at September 30, 2014 or September 30, 2013. We believe that if we were to incur a loss on any of these matters, the loss would not have a material effect on our financial condition. +(9) Quarterly Financial Data (Unaudited) +The sum of the earnings per common share may not equal the corresponding annual amounts due to interim quarter rounding. +For the Quarter Ended in Fiscal 2014 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +44,794 +$ +50,134 +$ +47,212 +$ +46,692 +Gross profit +28,007 +31,593 +29,242 +28,401 +Net earnings +7,426 +10,300 +8,835 +8,182 +Basic earnings per common share +0.18 +0.25 +0.21 +0.20 +Diluted earnings per common share +0.18 +0.24 +0.21 +0.20 +Cash dividends per common share +0.19 +0.20 +0.20 +0.20 +For the Quarter Ended in Fiscal 2013 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +45,351 +$ +47,265 +$ +47,108 +$ +48,962 +Gross profit +28,796 +30,743 +30,631 +30,874 +Net earnings +8,474 +10,249 +10,159 +9,150 +Basic earnings per common share +0.21 +0.25 +0.25 +0.22 +Diluted earnings per common share +0.20 +0.24 +0.24 +0.22 +Cash dividends per common share +0.38 +* +— +* +0.19 +0.19 +* +As a result of accelerating the declaration and payment of the quarterly cash dividend historically declared and paid during the second quarter of the fiscal year, two quarterly cash dividends were declared and paid +during the three months ended December 31, 2012, with none occurring during the three months ended March 31, 2013. +(10) Subsequent Events +We evaluated subsequent events after the balance sheet date of September 30, 2014 and there were no material subsequent events that +required recognition or additional disclosure in these financial statements. +- 72 - +Table of Contents +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE +Not applicable. +ITEM 9A. +CONTROLS AND PROCEDURES +As of +September 30, 2014, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended. Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure +controls and procedures were effective as of September 30, 2014. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal +quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2014. +Our internal control report is included in this Annual Report on Form 10-K after Item 8, under the caption “Management’s Report on Internal +Control over Financial Reporting.” +ITEM 9B. +OTHER INFORMATION +Not applicable. +- 73 - +Table of Contents +PART III. +The information required by Items 10., 11., 12. (other than that portion set forth below), 13. and 14., of Part +III are incorporated by reference from the Registrant’s Proxy Statement for its 2015 Annual Shareholders’ Meeting to be filed with the Commission pursuant to Regulation 14A. +ITEM 12. +EQUITY COMPENSATION PLAN INFORMATION +The +following table presents summary information as of September 30, 2014 with respect to all of our equity compensation plans (number of securities information in thousands). +Plan Category +(a) +Number of +Securities to be +issued upon +exercise of +outstanding +options, warrants +and rights +(b) +Weighted- +average exercise +price of +outstanding +options, +warrants and +rights +(c) +Number of securities +remaining available +for future issuance +under equity +compensation plans +(excluding +securities +reflected in column +(a)) +Equity compensation plans approved by security holders (1) +1,142 +$ +19.110 +3,703 +Total (2) +1,142 +$ +19.110 +3,703 +(1) +1996 Stock Option Plan, as amended in 2001 +2004 Equity Compensation Plan, as amended +2012 Stock Incentive Plan +(2) +Weighted-average remaining term of 5.08 years +- 74 - +Table of Contents +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) (1) and (2) FINANCIAL STATEMENTS AND SCHEDULES. +All +financial statements and schedules required to be filed by Item 8 of this Form and included in this report have been so identified under Item 8. No additional financial statements or schedules are being filed since the requirements of +paragraph (c) under Item 15 are not applicable to Meridian. +(b) (3) EXHIBITS. +Exhibit Number +Description of Exhibit +3.1 +Articles of Incorporation, including amendments not related to Company name change (Incorporated by reference to Registration Statement No. 333-02613 on Form S-3 filed with the Securities and Exchange Commission on April 18, 1996 +and Meridian’s Form 8-K filed with the Securities and Exchange Commission on May 16, 2007) +3.2 +Amended Code of Regulations (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on November 13, 2012) +10.1* +Savings and Investment Plan Prototype Adoption Agreement (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2003) +10.2* +Amendment No. 1 to Supplemental Benefit Agreement Dated September 23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on September +25, 2014) +10.3* +Supplemental Benefit Agreement between Meridian and John A. Kraeutler, as amended April 24, 2001, December 29, 2008, August 3, 2011 and June 12, 2012 (referred to as the Salary Continuation Agreement prior to June 12, 2012) +(Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on June 14, 2012) +10.4 +Dividend Reinvestment Plan (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 1999) +10.5* +Amendment No. 1 to Amended and Restated Employment Agreement Dated September 23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on +September 25, 2014) +10.6* +Amended and Restated Employment Agreement Dated June 12, 2012 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on June 14, +2012) +10.7* +Second Amended and Restated Agreement Concerning Disability and Death dated June 19, 2014, between Meridian, the Fifth Third Bank, Trustee of the Motto Family Irrevocable Wealth Accumulation Trust, and William J. Motto (Incorporated +by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2014) +- 75 - +Table of Contents +10.8* +2004 Equity Compensation Plan, amended and restated effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.9* +2012 Stock Incentive Plan, effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.10* +Fiscal 2015 Officer’s Performance Compensation Plan (Filed herewith) +10.11 +Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc. Meridian Life Science, Inc. and Fifth Third Bank dated August 1, 2007 (Incorporated by reference to +Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2007) +10.11.1 +Amended and Restated Revolving Note with Fifth Third Bank dated September 15, 2012 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2012) +10.11.2 +First Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated September 2, 2010 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.11.3 +Second Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated December 1, 2010 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.11.4 +Third Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated September 15, 2012 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2012) +10.12* +Sample Time-Based Restricted Share Unit Award Agreement dated November 6, 2014 (Filed herewith) +10.13* +Sample Performance Award Restricted Share Unit Award Agreement dated November 6, 2014 (Filed herewith) +10.14* +Meridian Bioscience, Inc. Change in Control Severance Compensation Policy dated March 18, 2011 (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on March 24, 2011) +13 +2014 Annual Report to Shareholders (1) +14 +Code of Ethics (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2003) +21 +Subsidiaries of the Registrant (Filed herewith) +23 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +- 76 - +Table of Contents +31.1 +Certification of Principal Executive Officer required by Rule 13a-14(a) (Filed herewith) +31.2 +Certification of Principal Financial Officer required by Rule 13a-14(a) (Filed herewith) +32 +Section 1350 Certification of Chief Executive Officer and Chief Financial Officer (Filed herewith) +101 +The following financial information from Meridian Bioscience Inc.’s Annual Report on Form 10-K for the fiscal year ended September 30, 2014 filed with the SEC on December 1, 2014, formatted in XBRL includes: (i) Consolidated +Statements of Operations for the years ended September 30, 2014, 2013 and 2012; (ii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2014, 2013 and 2012; (iii) Consolidated Statements of Cash Flows for the years +ended September 30, 2014, 2013 and 2012; (iv) Consolidated Balance Sheets as of September 30, 2014 and 2013; (v) Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2014, 2013 and 2012; and (vi) the Notes to +Consolidated Financial Statements. +* +Management Compensatory Contracts +(1) +Only specific portions of the 2014 Annual Report to Shareholders are incorporated by reference in this Form 10-K as filed herewith. A supplemental paper copy of the 2014 Annual Report to Shareholders has been furnished +to the Securities and Exchange Commission for informational purposes only. +Meridian will provide shareholders with any exhibit upon the +payment of a specified reasonable fee, which fee shall be limited to Meridian’s reasonable expenses in furnishing such exhibit. +- 77 - +Table of Contents +SIGNATURES +Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +MERIDIAN BIOSCIENCE, INC. +By: +/s/ John A. Kraeutler +Date: December 1, 2014 +John A. Kraeutler +Chairman of the Board and +Chief +Executive Officer +We, the undersigned directors and officers of the Registrant, hereby severally constitute John A. Kraeutler and Melissa +A. Lueke, and each of them singly, our true and lawful attorneys with full power to them and each of them to sign for us, in our names in the capacities indicated below, any and all amendments to the Annual Report on Form 10-K filed with the +Securities and Exchange Commission. +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following +persons on behalf of the Registrant and in the capacities and on the dates indicated. +Signature +Capacity +Date +/s/ John A. Kraeutler +Chairman of the Board and Chief Executive Officer +December 1, 2014 +John A. Kraeutler +/s/ Melissa A. Lueke +Melissa A. Lueke +Executive Vice President, Chief Financial Officer, and Secretary (Principal Financial and Accounting Officer) +December 1, 2014 +/s/ James M. Anderson +James M. Anderson +Director +December 1, 2014 +/s/ Dwight E. Ellingwood +Dwight E. Ellingwood +Director +December 1, 2014 +/s/ David C. Phillips +David C. Phillips +Director +December 1, 2014 +/s/ Robert J. Ready +Robert J. Ready +Director +December 1, 2014 +- 78 - +Table of Contents +SCHEDULE II +Meridian Bioscience, Inc. +and +Subsidiaries +Valuation and Qualifying Accounts +(Dollars in thousands) +Years Ended +September 30, 2014, 2013 and 2012 +Description +Balance at +Beginning +of Period +Charged to +Costs and +Expenses +Deductions +Other (a) +Balance at +End of +Period +Year Ended September 30, 2014: +Allowance for doubtful accounts +$ +233 +$ +116 +$ +(68 +) +$ +(9 +) +$ +272 +Inventory realizability reserves +2,499 +1,325 +(834 +) +(48 +) +2,942 +Valuation allowances – deferred taxes +296 +— +(296 +) +— +— +Year Ended September 30, 2013: +Allowance for doubtful accounts +$ +574 +$ +(116 +) +$ +(239 +) +$ +14 +$ +233 +Inventory realizability reserves +2,271 +1,132 +(938 +) +34 +2,499 +Valuation allowances – deferred taxes +450 +150 +(289 +) +(15 +) +296 +Year Ended September 30, 2012: +Allowance for doubtful accounts +$ +310 +$ +370 +$ +(89 +) +$ +(17 +) +$ +574 +Inventory realizability reserves +3,175 +198 +(1,024 +) +(78 +) +2,271 +Valuation allowances – deferred taxes +603 +— +(140 +) +(13 +) +450 +(a) +Balances reflect the effects of currency translation. +- 79 - \ No newline at end of file diff --git a/raw/filings/0000794172/2014/0001193125-14-428676/rpt_disclosure.txt b/raw/filings/0000794172/2014/0001193125-14-428676/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..267d51cd948aeab7ae4f223c4364cfd832e9fb49 --- /dev/null +++ b/raw/filings/0000794172/2014/0001193125-14-428676/rpt_disclosure.txt @@ -0,0 +1,13 @@ +TRANSACTIONS WITH RELATED PERSONS +During fiscal 2014, the Company leased certain office space from an entity controlled by Marco G. Calzavara, President and Managing Director, Meridian +Bioscience Europe. Payments made under such arrangements during fiscal 2014 totaled approximately $200,000. +Nasdaq rules require the +Company to conduct an appropriate review of related party transactions required to be disclosed by the Company pursuant to SEC Regulation S-K Item 404 for potential conflict of interest situations on an ongoing basis and that all such +transactions must be approved by the Audit Committee or another Committee comprised of independent Directors. As a result, the Audit Committee annually reviews all such related party transactions and approves each related party transaction if it +determines that it is in the best interests of the Company. Additionally, the Audit Committee’s Charter provides it the authority to review, approve and monitor transactions involving the Company and “related persons” (Directors and +Executive Officers or their immediate family members, or shareholders owning five percent or greater of the Company’s outstanding stock). This also covers any related person transaction that meets the minimum threshold for disclosure in the +proxy statement under the relevant SEC rules (generally, transactions involving amounts exceeding $120,000 in which a related person has a direct or indirect material interest). In considering the transaction, the Audit Committee may consider all +relevant factors, including, as applicable, (i) the Company’s business rationale for entering into the transaction; (ii) the alternatives to entering into a related person transaction; (iii) whether the transaction is on terms +comparable to those available to third parties, or in the case of employment relationships, to employees generally; (iv) the potential for the transaction to lead to an actual or apparent conflict of interest and any safeguards imposed to +prevent such actual or apparent conflicts; and (v) the overall fairness of the transaction to the Company. This policy is included in the Company’s Employee Handbook. The approval of such related person transactions are evidenced by +internal Company resolutions or memoranda. \ No newline at end of file diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/filing.txt b/raw/filings/0000794172/2015/0001193125-15-390041/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..62ecb9503d3889d4998f59df1168bbaf44f172c5 --- /dev/null +++ b/raw/filings/0000794172/2015/0001193125-15-390041/filing.txt @@ -0,0 +1,3700 @@ +10-K +1 +d74026d10k.htm +ANNUAL REPORT +Annual Report +Table of Contents +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +FOR ANNUAL +AND TRANSITION REPORTS +PURSUANT TO SECTIONS 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +x +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2015. +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM +TO +Commission File No. 0-14902 +MERIDIAN +BIOSCIENCE, INC. +3471 River Hills Drive +Cincinnati, Ohio 45244 +IRS Employer ID No. 31-0888197 +Incorporated under the Laws of Ohio +Phone: (513) 271-3700 +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange of which registered +Common Shares, No Par Value +The NASDAQ Stock Market LLC +(NASDAQ Global Select Market) +Securities Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the +registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES x NO ¨ +If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or +15(d) of the Securities Exchange Act. YES ¨ NO x +Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act +of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web +site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such +files). YES x NO ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K (Section 229.405 of this Chapter) is not contained +herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10–K or any amendment to this Form +10–K. YES x NO ¨ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See +definitions of “large accelerated filer” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +x +Accelerated filer +¨ +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule +12b-2). YES ¨ NO x +The aggregate market value of Common Shares held by non-affiliates as of March 31, 2015 was $786,958,969 based on a closing sale price of $19.08 per +share on March 31, 2015. As of October 31, 2015, 41,846,049 no par value Common Shares were issued and outstanding. +Documents +Incorporated by Reference +Portions of the Registrant’s Annual Report to Shareholders for the fiscal year ended September 30, 2015 furnished +to the Commission pursuant to Rule 14a-3(b) are incorporated by reference in Part II as specified and portions of the Registrant’s Proxy Statement to be filed with the Commission for its 2016 Annual +Shareholders’ Meeting are incorporated by reference in Part III as specified. +Table of Contents +MERIDIAN BIOSCIENCE, INC. +INDEX TO ANNUAL REPORT +ON FORM 10-K +Part I +Page +Item 1 +Business +5 +Item 1A +Risk Factors +17 +Item 1B +Unresolved Staff Comments +26 +Item 2 +Properties +26 +Item 3 +Legal Proceedings +27 +Item 4 +Mine Safety Disclosures +27 +Part II +Item 5 +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +27 +Item 6 +Selected Financial Data +28 +Item 7 +Management’s Discussion and Analysis of Financial Condition and Results of Operations +28 +Item 7A +Quantitative and Qualitative Disclosures about Market Risk +46 +Item 8 +Financial Statements and Supplementary Data +47 +Item 9 +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +75 +Item 9A +Controls and Procedures +75 +Item 9B +Other Information +75 +Part III +Item 10 +Directors, Executive Officers and Corporate Governance +76 +Item 11 +Executive Compensation +76 +Item 12 +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +76 +Item 13 +Certain Relationships and Related Transactions, and Director Independence +76 +Item 14 +Principal Accounting Fees and Services +76 +Item 15 +Exhibits and Financial Statement Schedules +77 +FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements. The Private Securities Litigation Reform Act of 1995 provides a safe harbor from civil +litigation for forward-looking statements accompanied by meaningful cautionary statements. Except for historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as +amended, and Section 21E of the Securities Exchange Act of 1934, which may be identified by words such as “estimates”, “anticipates”, “projects”, “plans”, “seeks”, “may”, +“will”, “expects”, “intends”, “believes”, “should” and similar expressions or the negative versions thereof and which also may be identified by their context. All statements that address operating +performance or events or developments that Meridian expects or anticipates will occur in the future, including, but not limited to, statements relating to per share diluted earnings and revenue, are forward-looking statements. Such statements, +whether expressed or implied, are based upon current expectations of the Company and speak only as of the date made. Specifically, Meridian’s forward-looking statements are, and will be, based on management’s then-current views and +assumptions regarding future events and operating performance. Meridian assumes no obligation to publicly update or revise any forward-looking statements even if experience or future changes make it clear that any projected results expressed or +implied therein will not be realized. These statements are subject to various risks, uncertainties and other factors that could cause actual results to differ materially, including, without limitation, the following: Meridian’s continued growth +depends, in part, on its ability to introduce into the marketplace enhancements of existing products or new products that incorporate technological advances, meet customer requirements and respond to products developed by Meridian’s +competition, and its ability to effectively sell such products. While Meridian has introduced a number of internally developed products, there can be no assurance that it will be successful in the future in introducing such products on a timely +basis. Meridian relies on proprietary, patented and licensed technologies, and the Company’s ability to protect its intellectual property rights, as well as the potential for intellectual property litigation, would impact its results. Ongoing +consolidations of reference laboratories and formation of multi-hospital alliances may cause adverse changes to pricing and distribution. Recessionary pressures on the economy and the markets in which our customers operate, as well as adverse trends +in buying patterns from customers, can change expected results. Costs and difficulties in complying with laws and regulations, including those administered by the United States Food and Drug Administration, can +Table of Contents +result in unanticipated expenses and delays and interruptions to the sale of new and existing products. The international scope of Meridian’s operations, including changes in the relative +strength or weakness of the U.S. dollar and general economic conditions in foreign countries, can impact results and make them difficult to predict. One of Meridian’s growth strategies is the acquisition of companies and product lines. There +can be no assurance that additional acquisitions will be consummated or that, if consummated, will be successful and the acquired businesses will be successfully integrated into Meridian’s operations. There may be risks that acquisitions may +disrupt operations and may pose potential difficulties in employee retention, and there may be additional risks with respect to Meridian’s ability to recognize the benefits of acquisitions, including potential synergies and cost savings or the +failure of acquisitions to achieve their plans and objectives. Meridian cannot predict the possible impact of U.S. health care legislation enacted in 2010 – the Patient Protection and Affordable Care Act, as amended by the Health Care and +Education Reconciliation Act – and any modification or repeal of any of the provisions thereof, and any similar initiatives in other countries on its results of operations. Efforts to reduce the U.S. federal deficit, breaches of Meridian’s +information technology systems and natural disasters and other events could have a materially adverse effect on Meridian’s results of operations and revenues. In addition to the factors described in this paragraph, Part I, Item 1A Risk +Factors contains a list and description of uncertainties, risks and other matters that may affect the Company. +Table of Contents +PART I. +This Annual Report on Form 10-K includes forward-looking statements about our business and results of operations that are subject to risks and uncertainties. +See “Forward-Looking Statements” above. Factors that could cause or contribute to such differences include those discussed in Item 1A. Risk Factors. In addition to the risk factors discussed herein, we are also subject to additional +risks and uncertainties not presently known to us or that we currently deem immaterial. If any of these risks and uncertainties develops into actual events, our business, financial condition or results of operations could be adversely affected. +Unless the context requires otherwise, references in this Annual Report on Form 10-K to “Meridian,” “we,” “us,” +“our,” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +In the discussion that follows, all dollars and +shares are in thousands (both tables and text), except per share data. +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in (i) the development, manufacture, sale and distribution of diagnostic +test kits, primarily for certain gastrointestinal, viral, respiratory and parasitic infectious diseases; (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch +reagents used by researchers and other diagnostic manufacturers; and (iii) the contract development and manufacture of proteins and other biologicals under cGMP conditions for use by biopharmaceutical and biotechnology companies engaged in +research for new drugs and vaccines. The Company was incorporated in Ohio in 1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form +8-K and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the Securities and Exchange Commission (SEC). These reports may also be +read and copied at the SEC’s public reference room at 100 F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these filings and other information regarding Meridian at +www.sec.gov . The information on our website is not and should not be considered part of this Annual Report on Form 10-K. +- 5 - +Table of Contents +Reportable Segments +Our reportable segments are Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. The Diagnostics segment consists of +manufacturing operations in Cincinnati, Ohio, and the sale and distribution of diagnostic test kits in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other +countries outside of the Americas and EMEA (rest of the world, or “ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, +Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically and abroad, including sales and business development offices in Singapore and Beijing, China +to further pursue growing revenue opportunities in Asia. The Life Science segment also includes the contract development and manufacture of cGMP clinical grade proteins and other biologicals for use by biopharmaceutical and biotechnology companies +engaged in research for new drugs and vaccines. Financial information for Meridian’s reportable segments is included in Note 7 to the consolidated financial statements. +Diagnostics Segment +Overview of Products and +Markets +Our primary source of revenues continues to be diagnostic products, with our Diagnostics segment providing 75% of consolidated net +revenues for fiscal 2015. Third-party revenues for this segment were $146,000, $142,000 and $145,000 for fiscal 2015, 2014 and 2013, respectively, reflecting a three-year compound annual growth rate of 4%. As of September 30, 2015, our +Diagnostics segment had approximately 360 employees in seven countries. +Our diagnostic products provide accuracy, simplicity and speed; enable early +diagnosis and treatment of common, acute medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that (i) are acute conditions where rapid diagnosis impacts patient outcomes; +(ii) have opportunistic demographic and disease profiles; (iii) are underserved by current diagnostic products; and (iv) have difficult sample handling requirements (stool, blood, urine and other body fluids). This approach has +allowed us to establish significant market share in our target disease states. +Our diagnostic products span a broad menu of testing platforms and +technologies, and also include transport media that store and preserve specimen samples from patient collection to laboratory testing. Our testing platforms include: +• +Isothermal DNA Amplification ( illumi gene ® brand ) – high sensitivity, molecular platform that is suitable for +virtually any size laboratory, whether centralized or decentralized; provides flexibility to process from 1 to 10 tests per run in generally under one hour; and requires no batching of samples. +• +Rapid Immunoassay ( TRU ® , Immuno Card ® and +Immuno Card STAT! ® brands) – single-use immunoassays that can be used in point-of-care settings; these tests have fast turnaround times +(generally under 20 minutes); and can reduce expensive send-outs for hospitals and outpatient clinics. +- 6 - +Table of Contents +• +Enzyme-linked Immunoassay (Premier ® brand) – batch immunoassay platform that can process up to 96 tests per run; is highly +accurate and economical; and is adaptable to automation. +Our diagnostic products are used principally in the detection of infectious +diseases caused by various bacteria, viruses, parasites and pathogens. Our focus product families in Diagnostics are: +1. +C. difficile – causative agent for antibiotic-associated diarrhea from a hospital-acquired infection +2. +Foodborne – Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy) +3. +H. pylori – stomach ulcers +4. +Respiratory – Group A Streptococcus , M. pneumonia (Mycoplasma) and Bordetella pertussis , among tests for other diseases +5. +Women’s Health & Sexually Transmitted Diseases (“STD”) – Group B Streptococcus , Chlamydia trachomatis , Neisseria gonorrhea , Herpes Simplex Virus Type 1 & Type +2 +Revenues within these focus product families accounted for 79%, 77% and 77% of our Diagnostics segment’s third-party revenues during +fiscal 2015, 2014 and 2013, respectively. These same product families accounted for 59%, 58% and 59% of consolidated net revenues in fiscal 2015, 2014 and 2013, respectively. +Our product portfolio includes over 140 diagnostic tests and transport media, and is marketed to acute care hospitals, reference laboratories and outpatient +clinics in over 70 countries around the world. +We continue to invest in new product development for our molecular testing platform, +illumi gene . This platform now has the following commercialized tests (assays): +1. +illumi gene ® C. difficile – commercialized in August 2010 +2. +illumi gene ® Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene ® Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene ® Mycoplasma ( M. pneumonia; walking pneumonia) – commercialized in June 2013 +5. +illumi gene ® Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene ® Chlamydia trachomatis – commercialized outside of U.S. in February 2015 +7. +illumi gene ® Neisseria gonorrhea – commercialized outside of U.S. in February 2015 +8. +illumi gene ® HSV 1&2 (Herpes Simplex Virus Type 1 & Type 2) – commercialized outside of U.S. in May 2015; commercialized in U.S. +in July 2015 +We have several additional illumi gene tests in development, including +bloodborne pathogens that are the causative agents for malaria. We have a robust pipeline of illumi gene opportunities and continue to add new assays to our illumi gene platform +menu. +- 7 - +Table of Contents +We believe that our illumi gene system has been well-accepted in +our global markets. We now have approximately 1,465 customer account placements. Of these account placements, approximately 1,300 accounts have completed evaluations and validations and are regularly purchasing product, with the balance of our +account placements being in some stage of product evaluation and/or validation. Of our account placements, we have over 400 accounts that are regularly purchasing, evaluating and/or validating two or more assays. +Market Trends +The global market for infectious +disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. More importantly, within this market, there is a continuing shift from +conventional testing, which requires highly trained personnel and lengthy turnaround times for test results, to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The increasing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. With rapid and accurate +diagnoses of infectious diseases, physicians can pinpoint appropriate therapies quickly, leading to faster recovery, shorter hospital stays and lower overall treatment cost. The creation of Accountable Care Organizations (ACOs) in our U.S. market, +in particular, has the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with ACOs and health care systems that are transitioning +from fee-for-service compensation models, to compensation models based on the total outcome costs of a given patient. Our C. difficile , Group B Streptococcus , Group A Streptococcus , and H. pylori products are all examples +of how a highly accurate diagnostic test on the front end can mitigate or reduce down-stream costs for antibiotic use, symptom-relieving drugs and hospital stays. +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing organizations and integrated delivery networks, +consolidation among reference laboratories, and acquisition of physician practices by hospitals. We utilize multi-year supply agreements to secure our business where possible and appropriate. +Cost containment pressures have also affected health care systems outside the U.S., particularly in Europe, where the health care systems are generally +government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing +and Focus Product Families +Our Diagnostics segment’s sales and distribution network consists of the following for each of the broad +geographic regions we serve: +- 8 - +Table of Contents +North America +In North America, our sales and distribution network consists of a direct sales force (U.S. only) complemented by independent distributors. The +use of independent distributors in the U.S. allows our products to reach any size health care facility and also provides our customers the option to purchase our products directly from Meridian or through an authorized distributor. Two independent +distributors in the U.S. accounted for 10% or more of consolidated net revenues in fiscal 2015, 2014 and 2013: Cardinal Healthcare Corporation and Thermo Fisher Scientific. Our revenues from Cardinal were approximately $29,000, $28,000 and $35,000 +during fiscal 2015, 2014 and 2013, respectively. Our revenues from Thermo Fisher were approximately $25,000, $23,000 and $25,000 during fiscal 2015, 2014 and 2013, respectively. +EMEA +In EMEA, our sales +and distribution network consists of direct sales forces in Belgium, France, Holland and Italy, and independent distributors in other European countries, Africa and the Middle East. We have implemented a direct sales presence in Germany and the U.K. +for our illumi gene products, and utilize independent distributors for our immunoassay products. We maintain a distribution center near Milan, Italy. +ROW +With the exception +of Australia, in which we utilize a direct sales force, we utilize independent distributors throughout the ROW. +Our Diagnostics segment’s focus +product families are described below: +C. difficile +C. difficile , causative agent of serious hospital acquired bacterial infections, is our largest product family, generating approximately $31,000 in +global revenues for fiscal 2015, a 12% decrease from fiscal 2014 – reflecting a combination of sales of our molecular-based and traditional immunoassay products, with our molecular product now representing approximately 80% of this product +category. This product family has experienced significant competition in recent years from new technologies, primarily other molecular testing platforms. See Competition discussion below. +Foodborne +Our foodborne product family achieved +approximately $25,000 in global revenues for fiscal 2015, an increase of 8%, with over 95% of such sales occurring in the U.S. Our foodborne products include tests for Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy). +In the U.S. market, we believe that there are potentially 20 million stool cultures that are tested annually for foodborne illnesses. We believe that we have less than a 20% market share for EHEC and less than a 5% market share for Campy. +- 9 - +Table of Contents +We are continuing to re-emphasize the benefits of increased sensitivity and faster turnaround time versus culture +methods in our marketing programs. The primary competition for our foodborne products is laboratory culture methods and an immunoassay EHEC shiga toxin test from one of our competitors. We believe that our test offers better workflow, less hands-on +time and quicker results, in addition to being fully compliant with CDC-recommended testing methods. +Helicobacter pylori +H. pylori , a bacterium found in the stomach, is a major cause of peptic ulcers and is linked to duodenal ulcers and stomach cancer. H. pylori +represents our second largest product family, generating approximately $30,000 in global revenues for 2015, or 6% growth. We offer both antibody and direct antigen tests in alternative formats (single-use and high volume batch). Our major +competition in this product family is alternative test methods, serology and urea breath, and the prescription of symptom-relieving medications. Over 75% of our H. pylori product sales are in the U.S., where our strategy for this product line +has been to partner with managed care companies to promote the health and economic benefits of a test and treat strategy, and to move physician behavior away from serology-based testing toward direct antigen testing. In the U.S. market, we believe +that there are potentially 30 million people suffering from peptic ulcers and we believe that we currently have an approximate 5% market share. +The patents for our H. pylori products are owned by us and expire in May 2016 in the U.S. and in 2017 in countries outside the U.S. We expect +competition with respect to our H. pylori products to increase upon the expiration of these patents in 2016 and 2017 as we currently market the only FDA-cleared test to detect H. pylori antigen in stool samples. Such competition may +have an adverse impact on our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In +order to mitigate any loss in revenues upon patent expiration, among other things, we are researching and experimenting with new products (e.g., detection of H. pylori on molecular platforms) and attempting to secure significant customers +under long-term contracts. We are unable to provide any assurances that we will be successful with any mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including +revenues and gross profit. +Respiratory +In addition to our immunoassay tests to detect influenza, which have been part of our product portfolio for a number of years, during the last +three years we have also introduced three molecular-based products on our illumi gene platform to detect various respiratory conditions. These molecular products, which are less seasonally-dependent than our +influenza products, include illumi gene Group A Strep (2012), illumi gene Mycoplasma (2013) and illumi gene Pertussis (2014). Since their +commercialization, these products have been widely accepted in the marketplace and during fiscal 2015 grew to represent over 40% of our total Respiratory product family revenues of $22,000. +- 10 - +Table of Contents +Women’s Health & STD +In December 2011, we introduced our illumi gene Group B Strep product to detect Group B Streptococcus (GBS) in +expectant mothers. Early detection of GBS, a major perinatal pathogen for both mothers and their infants that is associated with significant morbidity and mortality, is critical to the prevention and treatment of serious disease in infants. During +fiscal 2015, we expanded our illumi gene molecular product platform to include three additional tests directly related to women’s health; these include tests for Chlamydia trachomatis (Chlamydia), Neisseria +gonorrhea (Gonorrhea) and Herpes Simplex Virus Type 1 & Type 2. With the GBS and HSV tests available worldwide, and the Chlamydia and Gonorrhea tests currently commercialized only outside the U.S., revenues from these women’s +health & STD products grew to over $7,000 during 2015, and are currently expected to exceed $10,000 in fiscal 2016. +Competition +Our major competitors in molecular diagnostics are Cepheid and Becton Dickinson, who have systems with multiple-assay menus. We also face +competition in molecular diagnostics, but to a lesser degree, from companies such as Alere, Great Basin, Nanosphere and Quidel. These latter companies have a limited commercial menu and tend to compete strictly on price. We believe that our +molecular platform offers a number of competitive features: +• +Molecular assay sensitivity that is comparable to higher costing PCR; +• +Low capital investment with no instrument service cost; +• +Small footprint that is portable and does not consume much laboratory space; and +• +Product menu that fits with initiatives to improve clinical and economic outcomes. +Our major competitors in +rapid immunoassay diagnostics are primarily Alere and Quidel. These companies tend to compete strictly on price. We believe that with the breadth and depth of our product portfolio, we are well positioned to capitalize on the migration to molecular +testing. +Research and Development +Our +Diagnostics segment’s research and development organization, which is located at our corporate headquarters in Newtown, Ohio, a suburb of Cincinnati, has expertise in biochemistry, immunology, mycology, bacteriology, virology, parasitology and +molecular biology. Research and development expenses for the Diagnostics segment for fiscal 2015, 2014 and 2013 were approximately $10,000, $10,000 and $8,000, respectively. This research and development organization focuses its activities on new +product and new technology development, new applications for our existing technologies, and improvements to existing products. Research and development efforts may occur in-house or with collaborative partners. We believe that new product +development is a key source for sustaining revenue growth. The products within our illumi gene molecular platform and H. pylori product family were developed solely in-house. +- 11 - +Table of Contents +Manufacturing +Our immunoassay and molecular products require the production of highly specific and sensitive antigens, antibodies, primers and enzymes. While +we produce substantially all of our own requirements including monoclonal and polyclonal antibodies, and a variety of fungal, bacterial and viral antigens, currently a number of the raw materials used in our products, including our +illumi gene molecular products, are purchased from outside vendors. With the recent expansion of our molecular diagnostic manufacturing capacity at our Cincinnati, Ohio location, we brought in-house certain +molecular component manufacturing that was previously outsourced. We believe that we have sufficient manufacturing and sourcing capacity for anticipated growth over the next several years. +Intellectual Property, Patents and Licenses +We +own or license U.S. and foreign patents, most of which are for products manufactured by our Diagnostics segment. These patents are used in our manufacturing processes for selected products (method patents) or may relate to the design of the test +device technology format (design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully replicate our production and manufacturing technologies and processes. Our employees are required to sign +confidentiality and non-disclosure agreements designed to protect our proprietary products. Revenues from these products in fiscal 2015 and fiscal 2014 were as follows: +Product/Technology Family +Number of +products +% of fiscal year +consolidated revenues +2015 +2014 +illumi gene +8 +21 +% +20 +% +H. pylori +2 +14 +% +14 +% +Respiratory immunoassay +4 +2 +% +2 +% +Other +5 +1 +% +1 +% +Total patented products +19 +38 +% +37 +% +The patents for the illumi gene products are licensed from a third party under +a non-exclusive license agreement and expire between 2020 and 2022. These patents were issued in the U.S., European Community and other countries. The term of our license agreement runs until the last patent expires in 2022, at which point we will +be free to practice the patents without any restriction or royalty obligation. +The patents for our H. pylori products are +owned by us and expire in May 2016 in the U.S. and in 2017 outside the U.S. (principally, Australia, Canada, European Community and Japan). We expect competition with respect to our H. pylori products to increase upon the expiration of these +patents in 2016 and 2017 as we currently market the only FDA-cleared test to detect H. pylori antigen in stool samples. Such competition may have an adverse impact on our selling prices for these products or our ability to retain business at +prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to mitigate any loss in revenues upon patent expiration, we are researching and experimenting +with new products (e.g., detection of H. pylori in samples other than stool and detection of H. pylori on molecular platforms). We are unable to provide any assurances that we will be successful with any mitigation strategy or that any +mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and gross profit. +- 12 - +Table of Contents +The patents for our immunoassay respiratory products are owned by us and expire in 2022 (two products) and 2027 +(one product). These patents were issued in the U.S. and European Community, among other jurisdictions. +The remaining five patented products are spread +over multiple product families. These patents are either owned by us, or we are free to practice the patents without any restriction or royalty obligation. These patents, where still in effect, collectively expire between 2016 and 2027. +Government Regulation +Our diagnostic products are +regulated by the Food & Drug Administration (FDA) as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (FDCA). Under the FDCA, medical devices are classified into one of three classes (i.e., Class I, II or III). Class +I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally must receive “pre-market approval” from the FDA as to safety and effectiveness. +Each of the diagnostic products currently marketed by us in the United States has been cleared by the FDA pursuant to the 510(k) clearance process or is +exempt from such requirements. We believe that most, but not all, products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all Class II devices, will be eligible for 510(k) clearance; +however, we can make no assurances in this regard. Meridian’s TRU FLU ® rapid influenza assay was cleared in 2006 as a Class I device. In May 2014, the FDA proposed reclassifying +rapid influenza assays as a Class II device, requiring the submission of a new 510(k) application and subjecting TRU FLU and similar competitive devices to increased requirements for sensitivity. If the proposed rule becomes effective, Meridian +will have one year to bring its assay up to the new requirements or remove it from the market. Sales of the TRU FLU product totaled approximately $2,000 in fiscal 2015. +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, largely similar to that of the FDA. +Meridian’s Cincinnati manufacturing facility is certified to ISO 13485:2012. +- 13 - +Table of Contents +Medical Device Tax +On January 1, 2013, the medical device tax established as part of the U.S. health care reform legislation became effective and as a result, the Company +made its first required tax deposit near the end of January 2013. During fiscal 2015, 2014 and 2013, the Company recorded to cost of sales approximately $1,900, $1,750 and $1,300, respectively, of medical device tax expense related to this +legislation. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory and parasitic infectious +diseases. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses, or pandemics such as the H1N1 influenza outbreak during fiscal 2009. While we believe that the +breadth of our diagnostic product lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be impacted period over +period by such factors. +Life Science Segment +Overview of Products and Markets +Our Life Science +segment’s business focuses on the development, manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing +companies, as well as contract development and manufacturing services under clinical cGMP conditions. Third-party revenues for this segment were approximately $49,000, $47,000 and $44,000 for fiscal 2015, 2014 and 2013, respectively. As of +September 30, 2015, our Life Science segment had approximately 220 employees in seven countries. +Most of the revenues for our Life Science segment +currently come from the manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies focused on the +development of immunoassay and molecular tests. Approximately 65% of Life Science revenues are generated from the industrial market, defined as diagnostic manufacturers and the agriculture industry. This is an increasing focus of our Bioline +molecular component business, which historically focused on the academic/research market that comprises the remaining 35% of Life Science revenues. We utilize direct sales teams in key countries such as the U.S., the U.K., Germany, France, Australia +and Singapore. Opened in 2013, the Singapore sales and business development office is designed to increase our presence and our revenue opportunities in Asia for both molecular and immunoassay components. Additionally, in order to further pursue +revenue opportunities in Asia, and China in particular, during fiscal 2015 we opened a representative office in Beijing, China. We utilize a network of distributors in other major countries. During fiscal 2015, 16% of third-party revenues for this +segment were from two diagnostic manufacturing customers. +- 14 - +Table of Contents +Products such as antibodies, antigens and reagents are marketed primarily to diagnostic manufacturing customers +as a source of raw materials for their immunoassay products, or as an outsourced step in their manufacturing processes. For example, we supply a number of major diagnostic manufacturers with proteins used to detect hepatitis A and rubella. These +products are typically sold in bulk quantities, and may also be custom-designed for a particular manufacturer’s requirements. Sales efforts are focused on multi-year supply arrangements in order to provide stability in volumes and pricing. We +believe this benefits both us and our customers. +Molecular biology products such as PCR/qPCR reagents, nucleotides and competent cells are marketed to +academic/research and industrial customers. These products are used in measuring DNA and RNA in clinical and agricultural applications. These reagents improve the purity, yield and speed of PCR reactions. Products such as MyTaq™ and +SensiFAST™ are examples of this type of PCR/qPCR reagent. +Our clinical cGMP protein production facility in Memphis, Tennessee serves as an enabling +technology for process development and large-scale manufacturing for biologicals used in new drugs and vaccines. The size of the facility is intended to accommodate manufacturing requirements for Phase I and Phase II clinical trials for +biopharmaceutical, biotechnology and government agency customers. Our revenues for contract services were approximately $3,000 in each of fiscal 2015, 2014 and 2013. +Market Trends +Globally, sales of molecular +components are growing at a faster pace than immunoassay components, and this is consistent with our business in constant-currency. Geographic expansion is a significant strategy for our Life Science segment, along with further penetration into +industrial markets with our molecular products. +Competition +The market for bulk biomedical reagents is highly competitive. Important competitive factors include product quality, price, customer service, and reputation. +We face competitors, many of which have greater financial, research and development, sales and marketing, and manufacturing resources, and where sole-source supply arrangements do not exist. Customers also may choose to manufacture their biomedical +reagents in-house rather than purchase from outside vendors such as Meridian. +The academic/research market is highly fragmented. Individual purchases are +typically of small quantities. The breadth of product offerings, quality, price and service, including on-line capabilities and technical resources, are important factors to building customer loyalty and repeat purchases. +The market for contract manufacturing in a validated cGMP facility, such as our Memphis facility, is also competitive. Important competitive factors include +reputation, customer service and price. Although the product application for this facility was built from our existing expertise in cell culture manufacturing techniques, we face competitors with greater experience in contract manufacturing in a +clinical cGMP environment. +- 15 - +Table of Contents +Research and Development +Research and development expenses for our Life Science segment for each of fiscal 2015, 2014 and 2013 were approximately $3,000. This research and development +organization is involved in activities for our cGMP facility and development of new molecular reagent products. +Manufacturing and Government +Regulation +Our Life Science facilities are ISO 9001:2008 certified, and where appropriate, comply with Regulation EC 1069:2009. +The cGMP clinical grade proteins that are produced in our Memphis facility are intended to be used as “injectibles,” and, as such, they are produced +under cGMP Regulations for Biologics and Human Drugs under the auspices of the FDA. Following clinical trials, approval and licensing of these products is the responsibility of the applicant, who owns the rights to each protein. Typically, the +customer is the applicant, not Meridian Life Science. +Acquisitions +Acquisitions have played an important role in the growth of our businesses. Our acquisition objectives include, among other things: (i) enhancing product +offerings; (ii) improving product distribution capabilities; (iii) providing access to new markets; and/or (iv) providing access to key biologicals or new technologies that lead to new products. Although we cannot provide any +assurance that we will consummate any additional acquisitions in the future, nor can we provide any assurance that any acquisitions will accomplish these objectives, we expect that the potential for acquisitions will continue to provide +opportunities for revenue and earnings growth in the future. +During November 2015, we made a minority investment in Oasis Diagnostics ® Corporation in order to evaluate our interest in saliva diagnostics and collection devices. Oasis is located in Vancouver, Washington. +International Markets +International markets are an +important source of revenues and future growth opportunities for both of our segments. For both segments combined, revenues from customers located outside of North America approximated $49,000 or 25% of consolidated fiscal 2015 revenues, $55,000 or +29% of consolidated fiscal 2014 revenues, and $54,000 or 29% of consolidated fiscal 2013 revenues. We expect to continue to look to international markets as a source of new revenues and growth in the future. +- 16 - +Table of Contents +During fiscal 2015, currency exchange had an approximate $4,700 unfavorable impact on revenues; $3,200 within the +Diagnostics segment and $1,500 within the Life Science segment. This compares to currency exchange rates having an approximate $850 favorable impact on revenues in fiscal 2014; $600 favorable within the Diagnostics segment and $250 within the Life +Science segment. Due to natural hedge relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net earnings was not material during fiscal 2015, 2014 or 2013. +Environmental +We are a conditionally exempt, small +quantity generator of hazardous waste and have a U.S. EPA identification number. We are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. +ITEM 1A. +RISK FACTORS +In addition to the other +information set forth in this report, you should carefully consider the following factors, which could materially affect our business, financial condition, cash flows or future results. Any one of these factors could cause our actual results to vary +materially from recent results or from anticipated future results. The risks described below are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may +materially adversely affect our business, financial condition and/or operating results. +Risks Affecting Growth and Profitability of our Business +We may be unable to develop new products and services or acquire products and services on favorable terms. +The medical diagnostic and life science industries are characterized by ongoing technological developments and changing customer requirements. As such, our +results of operations and continued growth depend, in part, on our ability in a timely manner to develop or acquire rights to, and successfully introduce into the marketplace, enhancements of existing products and services or new products and +services that incorporate technological advances, meet customer requirements and/or respond to products developed by our competition. We cannot provide any assurance that we will be successful in developing or acquiring such rights to products and +services on a timely basis, or that such products and services will adequately address the changing needs of the marketplace, either of which could adversely affect our results of operations. +In addition, we must regularly allocate considerable resources to research and development of new products, services and technologies. The research and +development process generally takes a significant amount of time from design stage to product launch. This process is conducted in various stages. During each stage, there is a risk that we will not achieve our goals on a timely basis, or at all, +and we may have to abandon a product in which we have invested substantial resources. +- 17 - +Table of Contents +We may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions +we make. +One of our growth strategies is the acquisition of companies and/or products. Although additional acquisitions of companies and products +may enhance the opportunity to increase net earnings over time, such acquisitions could result in greater administrative burdens, increased exposure to the uncertainties inherent in marketing new products and financial risks of additional operating +costs. The principal benefits expected to result from any acquisitions we make will not be achieved fully unless we are able to successfully integrate the operations of the acquired entities with our operations and realize the anticipated synergies, +cost savings and growth opportunities from integrating these businesses into our existing businesses. We cannot provide any assurance that we will be able to identify and complete additional acquisitions on terms we consider favorable or that, if +completed, will be successfully integrated into our operations. +Revenues for our Diagnostics segment may be impacted by our reliance upon two key +distributors in North America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +Key Distributors +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 37% and 36%, respectively, of the Diagnostics segment’s total +revenues for fiscal 2015 and fiscal 2014, or 28% and 27%, respectively, of our consolidated revenues for fiscal 2015 and fiscal 2014. These parties distribute our products and other laboratory products to end-user customers. The loss of either of +these distributors could negatively impact our revenues and results of operations unless suitable alternatives were timely found or lost sales to one distributor were absorbed by another distributor. Finding a suitable alternative on satisfactory +terms may pose challenges in our industry’s competitive environment. As an alternative, we could expand our efforts to distribute and market our products directly. This alternative, however, would require substantial investment in additional +sales, marketing and logistics resources, including hiring additional sales and customer service personnel, which would significantly increase our future selling, general and administrative expenses, but would not necessarily result in lower net +income levels. +In addition, buying patterns of these two distributors may fluctuate from quarter to quarter, potentially leading to uneven concentration +levels on a quarterly basis. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory and parasitic infectious +diseases. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses, or pandemics such as H1N1 influenza. While we believe that the breadth of our diagnostic product +lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be negatively impacted period over period by such +factors. +- 18 - +Table of Contents +Changing Diagnostic Market Conditions +Changes in the U.S. health care delivery system have resulted in consolidation among reference laboratories and the formation of multi-hospital alliances, +reducing the number of institutional customers for diagnostic test products. Consolidation in the U.S. health care industry has also led to the creation of group purchasing organizations (GPOs) and integrated delivery networks (IDNs) that aggregate +buying power for hospital groups and put pressure on our selling prices. Due to such consolidation, we may not be able to enter into and/or sustain contractual or other marketing or distribution arrangements on a satisfactory commercial basis with +institutional customers, GPOs and IDNs, which could adversely affect our results of operations. +We could be adversely affected by health care +reform legislation. +Third-party payers for medical products and services, including state, federal and foreign governments, are increasingly +concerned about escalating health care costs and can indirectly affect the pricing or the relative attractiveness of our products by regulating the maximum amount of reimbursement they will provide for diagnostic testing services. Following years of +increasing pressure, during 2010 the U.S. government enacted comprehensive health care reform. At present, we are unable to predict what effect the legislation might ultimately have on reimbursement rates for our products. If reimbursement amounts +for diagnostic testing services are decreased in the future, such decreases may reduce the amount that will be reimbursed to hospitals or physicians for such services and consequently, could place constraints on the levels of overall pricing, which +could have a material effect on our revenues and/or results of operations. +In addition, on January 1, 2013, the medical device tax established as +part of the U.S. health care reform legislation became effective and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2015, 2014 and 2013, the Company recorded approximately $1,900, $1,750 and +$1,300, respectively, of Medical Device Tax expense, which is reflected as a component of cost of sales in the accompanying Consolidated Statements of Operations. +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +As part of the Budget Control Act passed in August 2011 to extend the federal debt limit and reduce government spending, $1.2 trillion in automatic spending +cuts (known as sequestration) were implemented in 2013. The sequestration requires a 2% cut in Medicare payments for all services, including our diagnostic tests, which, due to subsequent legislative amendments to the statute, will remain in effect +through 2024 unless Congressional action is otherwise taken. Government research funding has also been reduced as a result of the sequestration. On January 2, 2013, the American Taxpayer Relief Act of 2012 also was signed into law, which, among +other things, further reduces Medicare payments to providers such as hospitals, imaging centers and cancer treatment centers, and increases the statute of limitations period for the government to recover overpayments to providers from three to five +years. +- 19 - +Table of Contents +Such reductions in government health care spending or research funding could result in reduced demand for our +products or additional pricing pressure. Further, there is ongoing uncertainty regarding the federal budget and federal spending levels, including the possible impacts of a failure to increase the “debt ceiling.” Any U.S. government +default on its debt could have broad macroeconomic effects that could, among other things, raise our borrowing costs. Any future shutdown of the federal government or failure to enact annual appropriations could also have a material adverse impact +on our business. +Revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two diagnostic manufacturing customers were 16% of the Life Science +segment’s total revenues for each of fiscal 2015 and fiscal 2014, or 4% of our consolidated revenues for each of fiscal 2015 and fiscal 2014. Our Life Science segment has four other significant customers who purchase antigens, antibodies and +reagents, which together comprised 10% and 8%, respectively, of the segment’s total revenues for fiscal 2015 and fiscal 2014. Any significant alteration of buying patterns from these customers could adversely affect our period over period +revenues and results of operations. +Revenues relating to research, development and manufacturing services for our Life Science segment are generated on a +contract by contract basis. The nature of this business is such that each contract provides a unique product and/or service and corresponding revenue stream. While this business has historically generated annual revenues of approximately $2,000 to +$4,000, there can be no assurance that future contracts will be secured, and if secured, will be profitable. +Intense competition could adversely +affect our profitability. +The markets for our products and services are characterized by substantial competition and rapid change. Hundreds of +companies around the world supply diagnostic tests and immunoassay and molecular reagents. These companies range from multinational health care entities, for which diagnostics is one line of business, to small start-up companies. Many of our +competitors have significantly greater financial, technical, manufacturing and marketing resources than we do. We cannot provide any assurance that our products and services will be able to compete successfully with the products and services of our +competitors. +- 20 - +Table of Contents +We may face increased competition upon expiration of our H. pylori patents in 2016 and 2017. +Our patents related to our H. pylori products expire in May 2016 in the U.S. and in 2017 in countries outside the U.S. Revenues from our H. +pylori products were approximately $30,000 in fiscal 2015. We expect competition with respect to our H. pylori products to increase upon the expiration of these patents in 2016 and 2017 as we currently market the only FDA-cleared test to +detect H. pylori antigen in stool samples. Such competition may have an adverse impact on our selling prices for these products and our ability to retain business at prices acceptable to us, and consequently, adversely affect our future +results of operations and liquidity, including revenues and gross profit. In order to mitigate any loss in revenues upon patent expiration, among other things, we are researching and experimenting with new products (e.g., detection of H. pylori on +molecular platforms) and attempting to secure significant customers under long-term contracts. We are unable to provide any assurances that we will be successful with any mitigation strategy or that any mitigation strategy will prevent an adverse +effect on our future results of operations and liquidity, including revenues and gross profit. +We depend on international revenues, and our +financial results may be adversely impacted by foreign currency, regulatory or other developments affecting international markets. +We sell +products and services into approximately 70 countries. Approximately 25% and 29% of our net revenues for fiscal 2015 and 2014, respectively, were attributable to markets outside of North America. For fiscal 2015, approximately 35% of our +international revenues were from sales made in Euros and 40% were from sales made in U.S. dollars, with the remaining 25% primarily being a combination of sales made in British pounds, Australian dollars and Singapore dollars. We are subject to the +risks associated with fluctuations in the exchange rates for the Australian dollar, British pound, Euro and Singapore dollar to the U.S. dollar. We are also subject to other risks associated with international operations, including longer customer +payment cycles, tariff regulations, requirements for export licenses, instability of foreign governments, and governmental requirements with respect to the importation and distribution of medical devices and immunodiagnostic and molecular biology +reagents, all of which may vary by country. +Risks Affecting our Manufacturing Operations +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +Medical device diagnostics is a highly regulated industry. We cannot provide any assurance that we will be able to obtain necessary governmental clearances or +approvals or timely clearances or approvals to market future products in the United States and other countries. Costs and difficulties in complying with laws and regulations administered by the U.S. Food and Drug Administration, the U.S. Department +of Agriculture, the U.S. Department of Commerce, the U.S. Drug Enforcement Agency, the Centers for Disease Control or other regulators can result in unanticipated expenses and delays and interruptions to the sale of new and existing products. +Regulatory approval can be a lengthy, expensive and uncertain process, making the timing and costs of approvals difficult to predict. The failure to comply +with these regulations can result in delays in obtaining authorization to sell products, seizure or recall of products, suspension or revocation of authority to manufacture or sell products, and other civil or criminal sanctions. +- 21 - +Table of Contents +Significant interruptions in production at our principal manufacturing facilities and/or third-party +manufacturing facilities would adversely affect our business and operating results. +Products and services manufactured at facilities we own or +lease comprised a majority of our revenues. Our global supply of these products and services is dependent on the uninterrupted and efficient operation of these facilities. In addition, we currently rely on a small number of third-party manufacturers +to produce certain of our diagnostic products and product components. The operations of our facilities or these third-party manufacturing facilities could be adversely affected by power failures, natural or other disasters, such as earthquakes, +floods, tornadoes or terrorist threats. Although we carry insurance to protect against certain business interruptions at our facilities, there can be no assurance that such coverage will be adequate or that such coverage will continue to remain +available on acceptable terms, if at all. Any significant interruption in the Company’s or a third-party supplier’s manufacturing capabilities could materially and adversely affect our operating results. +We depend on sole-source suppliers for certain critical raw materials and components, and finished products. A supply interruption could adversely +affect our business. +Raw Materials and Components +Our diagnostic products are made from a wide variety of raw materials that are biological or chemical in nature, and that generally are available from multiple +sources of supply. We sole-source certain raw materials and components due to FDA regulations, which make it time consuming and costly to switch raw materials and components in FDA cleared products. If certain suppliers fail to supply required raw +materials or components, we will need to secure other sources which may require us to conduct additional development and testing and obtain regulatory approval. These activities require significant time and resources, and there is no assurance that +new sources will be secured or regulatory approvals, if necessary, will be obtained. +One third party manufactures our proprietary +illumi pro-10™ Incubator Reader (instrument), a component of our illumi gene molecular system. This instrument is manufactured exclusively for Meridian according to our +specifications. While other manufacturers for this type of instrument are available, we source solely from one manufacturer due to the FDA regulations and costs involved in clearing the system for marketing in the United States. If this third-party +manufacturer fails to supply us with instruments, we will need to secure another manufacturer, and it may take as long as 12 months to transfer instrument manufacturing. As revenues for our illumi gene molecular +system accounted for $41,000 or 21% of consolidated revenues for fiscal 2015, $37,000 or 20% for fiscal 2014 and $34,000 or 18% for fiscal 2013, an interruption in the manufacturing of this system could have a material adverse effect on our +operating results. +Additionally, one third party manufactures one certain reagent for use with our +illumi gene assays. While alternative suppliers exist, we elect to utilize this third party exclusively in order to maintain consistency in our materials, which is critical in complying with FDA regulatory +requirements. +- 22 - +Table of Contents +Finished Products +We outsource the manufacturing for certain finished diagnostic products to third parties. A disruption in the supply of these finished products could have a +material adverse effect on our business until we find another supplier or bring manufacturing in-house. +Four products manufactured exclusively for us by +three separate and independent companies accounted for 18%, 17% and 17% of consolidated revenues in fiscal 2015, 2014 and 2013, respectively. Meridian owns all rights and title to the FDA 510(k) clearances for these products. +Activities undertaken by Meridian to reduce the risk of these sole-supplier arrangements include maintaining adequate inventory levels, supplier qualification +procedures, supplier audits, site visits and frequent communication. Additionally, we have identified potential alternate suppliers. +Risks Related to +Intellectual Property and Product Liability +We may be unable to protect or obtain proprietary rights that we utilize or intend to utilize. +In developing and manufacturing our products, we employ a variety of proprietary and patented technologies. In addition, we have licensed, and +expect to continue to license, various complementary technologies and methods from academic institutions and public and private companies. We cannot provide any assurance that the technologies that we own or license provide protection from +competitive threats or from challenges to our intellectual property. In addition, we cannot provide any assurances that we will be successful in obtaining and retaining licenses or proprietary or patented technologies in the future. +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Litigation over intellectual property rights is prevalent in the diagnostic industry. As the market for diagnostics continues to grow and the number of +participants in the market increases, we may increasingly be subject to patent infringement claims. It is possible that a third party may claim infringement against us. If found to infringe, we may attempt to obtain a license to such intellectual +property; however, we may be unable to do so on favorable terms, or at all. Additionally, if our products are found to infringe on third-party intellectual property, we may be required to pay damages for past infringement and lose the ability to +sell certain products, causing our revenues to decrease. We currently carry intellectual property insurance that covers damages and defense costs from our potential infringement on certain other third-party patents at levels that we believe are +commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability and the damage +to our reputation in the industry could have a material adverse effect on our business. +- 23 - +Table of Contents +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and +may have to limit or cease sales of our products. +The testing, manufacturing and marketing of medical diagnostic products involves an inherent +risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We currently carry product liability +insurance at a level we believe is commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. In certain customer contracts, we indemnify third parties for certain product liability claims +related to our products. These indemnification obligations may cause us to pay significant sums of money for claims that are covered by these indemnifications. In addition, a defect in the design or manufacture of our products could have a material +adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage +to our reputation in the industry could have a material adverse effect on our business. +Other Risks Affecting Our Business +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +Our future success depends on our continued ability to attract, hire and retain highly qualified personnel, including our executive officers and scientific, +technical, sales and marketing employees, and their ability to manage growth successfully. If such key employees were to leave and we were unable to obtain adequate replacements, our operating results could be adversely affected. +Our bank credit agreement imposes restrictions with respect to our operations. +Our bank credit agreement contains a number of financial covenants that require us to meet certain financial ratios and tests. If we fail to comply with the +obligations in the credit agreement, we would be in default under the credit agreement. If an event of default is not cured or waived, it could result in acceleration of any indebtedness under our credit agreement, which could have a material +adverse effect on our business. At the present time, no borrowings are outstanding under our bank credit agreement. +We face risks related to global +economic conditions. +We currently generate significant operating cash flows, which combined with access to the credit markets, provides us with +discretionary funding capacity for research and development and other strategic activities. However, as an enterprise with global operations and markets, our operations and financial performance are in part dependent upon global economic conditions, +and we could be negatively impacted by a global, regional or national economic crisis, including sovereign risk in the event of deterioration in the credit worthiness of or a default by local governments. We are particularly susceptible to the +economic conditions in countries where government-sponsored health care systems are the primary payers for health care, including those countries within the European Union that are reducing their public expenditures in an effort to achieve cost +savings. The uncertainty in global economic conditions poses a risk to the overall economy that could impact demand for our products, as well as our ability to manage normal commercial relationships with our customers, suppliers and creditors, +including financial institutions. As such, if global economic conditions deteriorate significantly, our business could be negatively impacted, including such areas as reduced demand for our products from a slow-down in the general economy, supplier +or customer disruptions resulting from tighter credit markets, and/or temporary interruptions in our ability to conduct day-to-day transactions through our financial intermediaries involving the payment to or collection of funds from our customers, +vendors and suppliers. While to-date such factors have not had a significant negative impact on our results or operations, we continue to monitor and plan for the potential impact of these global economic factors. +- 24 - +Table of Contents +Approximately $1,600 and $2,700 of our accounts receivable at September 30, 2015 and September 30, +2014, respectively, was due from Italian hospital customers whose funding ultimately comes from the Italian government. In addition, the amount of our annual revenues in the country of Greece and the corresponding amount of customer receivables +outstanding at any point in time is not significant, and therefore, we do not expect any meaningful impact from the financial crisis in the country of Greece. +Breaches of our information technology systems could have a material adverse effect on our operations. +We rely on information technology systems to process, transmit and store electronic information in our day-to-day operations. Like many multinational +corporations, our information technology systems may be subjected to computer viruses or other malicious codes, unauthorized access attempts, and cyber- or phishing-attacks. We also store certain information with third parties that could be subject +to these types of attacks. Such attacks could result in our intellectual property and other confidential information being lost or stolen, disruption of our operations, and other negative consequences, such as increased costs for security measures +or remediation costs, and diversion of management attention. While we will continue to implement additional protective measures to reduce the risk of and detect cyber incidents, cyber-attacks are becoming more sophisticated and frequent, and the +techniques used in such attacks change rapidly. There can be no assurances that our protective measures will prevent attacks that could have a significant impact on our business. +Natural disasters, war and other events could adversely affect our future revenues and operating income. +Natural disasters (including pandemics), war, terrorism, labor disruptions and international conflicts, and actions taken by the United States and other +governments or by our customers or suppliers in response to such events, could cause significant economic disruption and political and social instability in the United States and in areas outside of the United States in which we operate. These +events could result in decreased demand for our products, adversely affect our manufacturing and distribution capabilities, or increase the costs for or cause interruptions in the supply of materials from our suppliers. +- 25 - +Table of Contents +Risks Related to Our Common Stock +Our board of directors has the authority to issue up to 1,000 shares of undesignated preferred stock and to determine the rights, preferences, privileges and +restrictions, including voting rights, of such shares without any future vote or action by the shareholders. The issuance of preferred stock under certain circumstances could have the effect of delaying or preventing a change in control of our +company. Ohio corporation law contains provisions that may discourage takeover bids for our company that have not been negotiated with the board of directors. Such provisions could limit the price that investors might be willing to pay in the future +for shares of our common stock. In addition, sales of substantial amounts of such shares in the public market could adversely affect the market price of our common stock and our ability to raise additional capital at a price favorable to us. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Our corporate offices, +Diagnostics manufacturing facility and Diagnostics research and development facility are located in five buildings totaling approximately 120,000 square feet on 10 acres of land in the Village of Newtown, a suburb of Cincinnati, Ohio. These +properties are owned by us. We also operate a Diagnostics sales and distribution center near Milan, Italy in an approximately 18,000 square foot two-story building. This facility is owned by our wholly-owned Italian subsidiary, Meridian Bioscience +Europe s.r.l. We also rent office space in Paris, France and Braine-l’Alleud, Belgium for sales and administrative functions. +Our Life Science +operations are conducted in several facilities in Memphis, Tennessee; Boca Raton, Florida; Taunton, Massachusetts; London, England; Luckenwalde, Germany; Sydney, Australia; Singapore; and Beijing, China. Our facility in Memphis, Tennessee consists +of two buildings totaling approximately 44,000 square feet and is owned by us. Our leased facility in Boca Raton, Florida contains approximately 7,500 square feet of manufacturing space. Following are details of our other Life Science facilities, +all of which are leased: Taunton – approximately 10,000 square feet of sales and warehouse space; London – approximately 20,000 square feet of sales, warehouse, distribution, research and development, manufacturing and administrative +office space; Luckenwalde – approximately 10,000 square feet of sales, warehouse and manufacturing space; Sydney – approximately 8,000 square feet of sales, warehouse, research and development and manufacturing space; Singapore – +approximately 2,000 square feet of sales and business development space; Beijing – less than 1,000 square feet of representative office space maintained for business development purposes. +- 26 - +Table of Contents +ITEM 3. +LEGAL PROCEEDINGS +We are a party to +various litigation matters that we believe are in the normal course of business. The ultimate resolution of these matters is not expected to have a material adverse effect on our financial position, results of operations or cash flows. No material +provision has been made in the accompanying consolidated financial statements for these matters. +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +PART II. +ITEM 5. +MARKET FOR REGISTRANT’S COMMON +EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Refer to “Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on Pages 17 through +26 of this Annual Report. +“Common Stock Information” on the inside back cover of the Annual Report to Shareholders for 2015 and +“Quarterly Financial Data (Unaudited)” relating to our dividends in Note 9 to the Consolidated Financial Statements are incorporated herein by reference. Except as may otherwise be prohibited by applicable law, there are no restrictions on +cash dividend payments. +During fiscal 2015, our indicated annual dividend rate of $0.80 per share approximated 94% of full year diluted earnings per +share, exceeding our long-standing policy of establishing a cash dividend payout ratio of between 75% and 85% of each fiscal year’s expected net earnings. Despite there being certain individual fiscal years in which our payout ratio has fallen +outside of this policy range, since adopting this policy in November 2002, our cumulative cash dividend payout has approximated 85% of cumulative net earnings during this timeframe. The declaration and amount of dividends will be determined by the +board of directors in its discretion based upon its evaluation of earnings, cash flow requirements and future business developments and opportunities, including acquisitions. At its meeting on November 4, 2015, the board of directors announced +a continuation of the $0.80 indicated annual dividend rate per share for fiscal 2016. We paid dividends of $0.80 per share in fiscal 2015, $0.79 per share in fiscal 2014 and $0.76 per share in fiscal 2013. +As of September 30, 2015, there were approximately 800 holders of record and approximately 16,500 beneficial owners of our common shares. +- 27 - +Table of Contents +ITEM 6. +SELECTED FINANCIAL DATA +Incorporated by +reference from inside front cover of the Annual Report to Shareholders for 2015. +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Refer to “Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on Pages 17 +through 26 of this Annual Report. +In the discussion that follows, all amounts are in thousands (both tables and text), except per share data . +Results of Operations : +Fourth Quarter +Net earnings for the fourth quarter of fiscal 2015 increased 3% to $8,467, or $0.20 per diluted share, from net earnings for the fourth quarter of +fiscal 2014 of $8,182, or $0.20 per diluted share. Consolidated revenues for the fourth quarter of fiscal 2015 increased $376, or 1%, to $47,068 compared to the fourth quarter of fiscal 2014; increasing 4% on a constant-currency basis. +Included within the fourth quarter 2015 results were revenues from our illumi gene ® +molecular platform of products totaling $10,215, representing a 12% increase from the fiscal 2014 fourth quarter. Also contributing to the consolidated revenues increase were increased revenues in three of our diagnostic focus product families +(foodborne, respiratory and women’s health & STD) and our Life Science segment’s molecular components business. Serving to partially offset these increases were decreased revenues in our C. difficile and H. pylori +focus product families and our Life Science segment’s immunoassay components business. +Revenues for the Diagnostics segment for the fourth +quarter of fiscal 2015 increased 1% compared to the fourth quarter of fiscal 2014 (3% on a constant-currency basis), reflecting the following for each of our focus product families: 6% growth in our foodborne products, 39% in our women’s +health & STD products, 42% growth in our respiratory products, 5% decline in our H. pylori products and 17% decline in our C. difficile products. As it relates to our respiratory products, the growth was driven by several +products in both our molecular and immunoassay categories. Our molecular products ( illumi gene Group A Strep, illumi gene Mycoplasma and illumi gene Pertussis) +experienced volume growth from new assay placements. Our immunoassay products (influenza and Mycoplasma) experienced growth in distribution channels. With growth in its molecular components business and a decline in its immunoassay components +business, revenues of our Life Science segment were flat in the fourth quarter of fiscal 2015 compared to the fourth quarter of fiscal 2014; increasing 4% on a constant-currency basis. +- 28 - +Table of Contents +Fiscal Year +Net earnings for fiscal 2015 increased 2% to $35,540, or $0.85 per diluted share, from net earnings for fiscal 2014 of $34,743, or $0.83 per diluted share. +REVENUE OVERVIEW +Below are analyses of the +Company’s revenue, provided for each of the following: +- By Reportable Segment & Geographic Region +- By Product Platform/Type +- By +Disease Family (Diagnostics only) +Revenue Overview- By Reportable Segment & Geographic Region +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, and the sale and +distribution of diagnostic test kits in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, +or “ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, +PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically and abroad, including sales and business development offices in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. The Life +Science segment also includes the contract development and manufacture of cGMP clinical grade proteins and other biologicals for use by biopharmaceutical and biotechnology companies engaged in research for new drugs and vaccines. +Revenues for the Diagnostics segment, in the normal course of business, may be affected from quarter to quarter by buying patterns of major distributors, +seasonality and strength of certain diseases, and foreign currency exchange rates. Revenues for the Life Science segment, in the normal course of business, may be affected from quarter to quarter by the timing and nature of arrangements for contract +services work, which may have longer production cycles than bioresearch reagents and bulk antigens and antibodies, as well as buying patterns of major customers, and foreign currency exchange rates. We believe that the overall breadth of our product +lines serves to reduce the variability in consolidated revenues due to these factors. +- 29 - +Table of Contents +Revenues for each of our segments and the geographic regions therein are shown below. +2015 +2014 +2013 +2015 vs. +2014 +Inc (Dec) +2014 vs. +2013 +Inc (Dec) +Diagnostics- +Americas +$ +123,366 +$ +114,754 +$ +116,509 +8 +% +(2 +)% +EMEA +19,135 +21,807 +21,378 +(12 +)% +2 +% +ROW +3,613 +4,939 +6,742 +(27 +)% +(27 +)% +Total Diagnostics +146,114 +141,500 +144,629 +3 +% +(2 +)% +Life Science- +Americas +22,363 +19,040 +17,688 +17 +% +8 +% +EMEA +17,845 +20,005 +18,721 +(11 +)% +7 +% +ROW +8,508 +8,287 +7,648 +3 +% +8 +% +Total Life Science +48,716 +47,332 +44,057 +3 +% +7 +% +Consolidated +$ +194,830 +$ +188,832 +$ +188,686 +3 +% +— +% +% of total revenues- +Diagnostics +75 +% +75 +% +77 +% +Life Science +25 +% +25 +% +23 +% +Total +100 +% +100 +% +100 +% +Ex-Americas +25 +% +29 +% +29 +% +Revenue Overview- By Product Platform/Type +The revenues generated by each of our reportable segments result primarily from the sale of the following segment-specific categories of products: +Diagnostics +1) +Molecular tests that operate on our illum i gene platform +2) +Immunoassay tests on multiple technology platforms +Life Science +1) +Molecular components +2) +Immunoassay components +- 30 - +Table of Contents +Revenues for each product platform/type, as well as its relative percentage of segment revenues, are shown below. +2015 +2014 +2013 +2015 vs. +2014 +Inc (Dec) +2014 vs. +2013 +Inc (Dec) +Diagnostics- +Molecular tests +$ +40,880 +$ +36,981 +$ +33,597 +11 +% +10 +% +Immunoassay tests +105,234 +104,519 +111,032 +1 +% +(6 +)% +Total Diagnostics +$ +146,114 +$ +141,500 +$ +144,629 +3 +% +(2 +)% +Life Science- +Molecular components +$ +20,601 +$ +20,824 +$ +18,777 +(1 +)% +11 +% +Immunoassay components +28,115 +26,508 +25,280 +6 +% +5 +% +Total Life Science +$ +48,716 +$ +47,332 +$ +44,057 +3 +% +7 +% +% of Diagnostics revenues- +Molecular tests +28 +% +26 +% +23 +% +Immunoassay tests +72 +% +74 +% +77 +% +Total Diagnostics +100 +% +100 +% +100 +% +% of Life Science revenues- +Molecular components +42 +% +44 +% +43 +% +Immunoassay components +58 +% +56 +% +57 +% +Total Life Science +100 +% +100 +% +100 +% +Following is a discussion of the revenues generated by each of these product platforms/types: +Diagnostics Products +illumi gene Molecular Platform Products +During fiscal 2015, revenues from our illumi gene molecular platform of products totaled $40,880, representing an 11% increase from the +fiscal 2014. We have approximately 1,465 customer account placements. Of these account placements, approximately 1,300 accounts have completed evaluations and validations and are regularly purchasing product, with the balance of our account +placements being in some stage of product evaluation and/or validation. Of our account placements, we have over 400 accounts that are regularly purchasing, evaluating and/or validating two or more assays. +We continue to invest in new product development for our molecular testing platform, illumi gene . This platform now has the following +commercialized tests: +1. +illumi gene ® C. difficile – commercialized in August 2010 +2. +illumi gene ® Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene ® Group A Streptococcus (Group A Strep) – commercialized in September 2012 +- 31 - +Table of Contents +4. +illumi gene ® Mycoplasma (M. pneumonia; walking pneumonia) – commercialized in June 2013 +5. +illumi gene ® Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene ® Chlamydia trachomatis – commercialized outside of U.S. in February 2015 +7. +illumi gene ® Neisseria gonorrhea – commercialized outside of U.S. in February 2015 +8. +illumi gene ® HSV 1&2 (Herpes Simplex Virus Type 1 & Type 2) – commercialized outside of U.S. in May 2015; commercialized in U.S. +in July 2015 +We have several additional illumi gene tests in development, including +bloodborne pathogens that are the causative agents for malaria. We have a robust pipeline of illumi gene opportunities and continue to add new assays to our illumi gene platform +menu. +We believe that the diagnostic testing market is continuing to selectively move away from culture and immunoassay +testing to molecular testing for diseases where there is a favorable cost/benefit position for the total cost of health care. While this market is competitive, with molecular companies such as Cepheid and Becton Dickinson and others such as Quidel, +Great Basin, Nanosphere, and Alere, we believe we are well positioned to capitalize on the migration to molecular testing. Our simple, easy-to-use, illumi gene platform, with its expanding menu, requires no +expensive equipment purchase and little to no maintenance cost. We believe these features, along with its small footprint and the performance of the illumi gene assays, make +illumi gene an attractive molecular platform to any size hospital or physician office laboratory that runs moderately-complex tests. +Immunoassay Products +Revenues from our +Diagnostics segment’s immunoassay products increased 1% in fiscal 2015, following a 6% decrease in fiscal 2014. As described in the product discussions below, the current year increase results primarily from the revenue growth of our foodborne +and H. pylori products, partially offset by the decline in revenues from our C. difficile and respiratory immunoassay products. +Life Science Products +During fiscal 2015, revenues from +our Life Science segment increased 3%, with revenues from molecular components sales decreasing 1% from fiscal 2014 and revenues from immunoassay components sales increasing 6%. Life Science segment revenues increased 7% in fiscal 2014, with +revenues from molecular component sales increasing 11% over fiscal 2013 and revenues from immunoassay component sales increasing 5%. Our molecular components business’ growth was negatively impacted by the movement in currency exchange rates +since fiscal 2014, with revenues increasing 6% on a constant-currency basis over fiscal 2014. Our Life Science segment continued to benefit from increased sales into China, with such sales totaling approximately $2,100 during fiscal 2015 +(approximately $600 in the molecular components business and $1,500 in the immunoassay components business). +- 32 - +Table of Contents +Diagnostics Revenue Overview- By Disease Family +Revenues from our focus families ( C. difficile , foodborne, H. pylori , respiratory and women’s health & STD) comprised 79%, +77% and 77% of our Diagnostics segment’s revenues during fiscal 2015, 2014 and 2013, respectively. Following is a discussion of the revenues generated by each product family: +C. difficile Products +During fiscal 2015, +revenues for our C. difficile product family decreased 12% to $31,000. This followed a decrease of 12% in fiscal 2014. Our molecular products now represent approximately 80% of this product category. The C. difficile test market +continues to be highly competitive, with over 10 suppliers in the United States, certain of which choose to compete solely on price. During fiscal 2015, the amount and rate of decline in constant-currency revenues has decreased. We believe this is +due largely to the expansion of our illumi gene molecular platform menu having a positive effect on defending our C. difficile business. +Foodborne Products +Revenues for our +foodborne products (Enterohemorrhagic E. coli (EHEC) and Campylobacter ), all of which are immunoassay products, totaled $25,000 during fiscal 2015, an 8% increase from fiscal 2014 (9% in constant-currency). During fiscal 2014, this +product line experienced a 3% decrease in revenues from the previous year. Revenues for our foodborne products on a quarterly basis (up 5% in the first quarter, up 27% in the second quarter, down 2% in the third quarter and up 6% in the fourth +quarter) have been affected by distributor ordering patterns and our inside and field sales programs, which are designed to protect and expand our current customer base. We are continuing to re-emphasize the benefits of increased sensitivity and +faster turnaround time versus culture methods in our marketing programs. The primary competition for our foodborne products is laboratory culture methods and an immunoassay EHEC shiga toxin test from one of our competitors. We believe that our test +offers better workflow, less hands-on time and quicker results, in addition to being fully compliant with CDC-recommended testing methods. +H. pylori Products +During fiscal 2015, +revenues from our H. pylori products, all of which are immunoassay products, increased 6% (10% in constant-currency) to $30,000, which followed a 7% increase during fiscal 2014. This increase continues to reflect the benefits of our +partnerships with managed care companies in promoting (i) the health and economic benefits of a test and treat strategy; (ii) changes in policies that discourage the use of traditional serology methods and promote the utilization of active +infection testing methods; and (iii) physician behavior movement away from serology-based testing and toward direct antigen testing. A significant amount of the H. pylori product revenues are to reference labs, whose buying patterns may +not be consistent period to period. +- 33 - +Table of Contents +The patents for our H. pylori products are owned by us and expire in May 2016 in the U.S. and in +2017 in countries outside the U.S. We expect competition with respect to our H. pylori products to increase upon the expiration of these patents in 2016 and 2017 as we currently market the only FDA-cleared test to detect H. pylori +antigen in stool samples. Such competition may have an adverse impact on our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and +liquidity, including revenues and gross profit. In order to mitigate any loss in revenues upon patent expiration, among other things, we are researching and experimenting with new products (e.g., detection of H. pylori on molecular platforms) +and attempting to secure significant customers under long-term contracts. We are unable to provide any assurances that we will be successful with any mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future +results of operations and liquidity, including revenues and gross profit. +Respiratory Products +Total respiratory revenues from our Diagnostics segment increased 27% to $22,000 during fiscal 2015, following a 5% decrease in the revenues from +such products in fiscal 2014. Growth was driven by several products in both our molecular and immunoassay categories. Our molecular products ( illumi gene Group A Strep, illumi gene +Mycoplasma and illumi gene Pertussis) experienced volume growth from new assay placements. Our immunoassay products (influenza and Mycoplasma) experienced growth as a result of increases in Japanese orders of our +Mycoplasma product and a large purchase by a distributor of influenza product in advance of the influenza season. +Women’s +Health & STD Products +During fiscal 2015, revenues from our women’s health & STD products, all of which are +molecular products, increased 20% to $7,000. This growth reflects our commercialization during fiscal 2015 of three illumi gene tests for sexually transmitted diseases (Chlamydia, Gonorrhea and HSV), along with +revenue growth for our illumi gene Group B Strep product, which was introduced to the market in December 2011. +Foreign Currency +During fiscal 2015, currency +exchange had an approximate $4,700 unfavorable impact on revenues; $3,200 within the Diagnostics segment and $1,500 within the Life Science segment. This compares to currency exchange rates having an approximate $850 favorable impact on revenues in +fiscal 2014; $600 favorable within the Diagnostics segment and $250 within the Life Science segment. Due to natural hedge relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net +earnings was not material during fiscal 2015, 2014 or 2013. +- 34 - +Table of Contents +Significant Customers +Two U.S. distributors accounted for 37%, 36% and 42% of our Diagnostics segment’s total revenues for fiscal 2015, 2014 and 2013, respectively. These +revenues represented 28%, 27% and 32% of consolidated revenues for fiscal 2015, 2014 and 2013, respectively. +Within our Life Science segment, two +diagnostic manufacturing customers accounted for 16%, 16% and 17% of the segment’s total revenues for fiscal 2015, 2014 and 2013, respectively. These revenues represented 4% of our consolidated revenues for each of fiscal 2015, 2014 and 2013. +Medical Device Tax +On January 1, 2013, +the medical device tax established as part of the U.S. health care reform legislation became effective, and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2015, 2014 and 2013, the Company +recorded approximately $1,900, $1,750 and $1,300, respectively, of medical device tax expense, which is reflected as a component of cost of sales in the accompanying Consolidated Statements of Operations. +Gross Profit: +2015 +2014 +2013 +2015 vs. +2014 +Inc (Dec) +2014 vs. +2013 +Inc (Dec) +Gross Profit +$ +121,882 +$ +117,243 +$ +121,044 +4 +% +(3 +)% +Gross Profit Margin +63 +% +62 +% +64 +% +1 point +-2 points +The overall gross profit margin increase during fiscal 2015 primarily results from the combined effects of (i) mix of +products sold; (ii) realization of manufacturing facility efficiencies; and (iii) favorable effects of currency rates related to products where the purchase cost is denominated in Euros but the customer sales are billed in U.S. dollars. +The overall decrease in the gross profit margin from fiscal 2013 to fiscal 2014 reflects the combined effects of (i) mix of revenues from the Company’s segments; (ii) mix of products sold; (iii) declines in pricing on selected +products; (iv) unfavorable manufacturing facility overhead absorption; and (v) the medical device tax, which did not exist during the first quarter of fiscal 2013. +Our overall operations consist of the sale of diagnostic test kits for various disease states and in alternative test formats, as well as bioresearch +reagents, bulk antigens and antibodies, PCR/qPCR reagents, nucleotides, competent cells, proficiency panels, and contract research and development, and contract manufacturing services. Product revenue mix shifts, in the normal course of business, +can cause the consolidated gross profit margin to fluctuate by several points. +- 35 - +Table of Contents +Operating Expenses: +Research & +Development +Selling & +Marketing +General & +Administrative +Total Operating +Expenses +2013 Expenses +$ +10,787 +$ +22,424 +$ +30,519 +$ +63,730 +% of Revenues +6 +% +12 +% +16 +% +34 +% +Fiscal 2014 Increases (Decreases): +Diagnostics +1,701 +1,289 +(2,036 +) +954 +Life Science +64 +1,197 +(1,094 +) +167 +2014 Expenses +$ +12,552 +$ +24,910 +$ +27,389 +$ +64,851 +% of Revenues +7 +% +13 +% +15 +% +34 +% +% Increase (Decrease) +16 +% +11 +% +(10 +%) +2 +% +Fiscal 2015 Increases (Decreases): +Diagnostics +(306 +) +730 +745 +1,169 +Life Science +359 +(39 +) +(518 +) +(198 +) +2015 Expenses +$ +12,605 +$ +25,601 +$ +27,616 +$ +65,822 +% of Revenues +6 +% +13 +% +14 +% +34 +% +% Increase +— +3 +% +1 +% +1 +% +Total operating expenses increased during both fiscal 2015 and fiscal 2014, while remaining consistent as a percentage of +consolidated revenues. Fiscal 2015 expenses primarily reflect the combined net effects of our (i) ongoing efforts to control spending in each of our segments; and (ii) favorable effects of currency rates. +During fiscal 2014, the increase in operating expenses resulted in large part from the combined net effects of our (i) ongoing efforts to control +spending in each of our segments, while investing the necessary resources in our strategic areas of growth, including increased investment in Research & Development for our molecular platform products and increased investment in Sales and +Marketing personnel and programs; and (ii) decreased incentive compensation compared to fiscal 2013 in light of the decline in corporate-wide operating profits. +Operating expenses for the Diagnostics segment increased $1,169 for fiscal 2015 compared to fiscal 2014, and increased $954 for fiscal 2014 compared to fiscal +2013. These overall increases result largely from the combined effects of (i) currency exchange rates (decrease of $1,100 for fiscal 2015 and increase of $200 for fiscal 2014); and (ii) the following: +Fiscal 2015 +Selling & Marketing +Increase in personnel costs resulting from increased Sales and Marketing headcount, and increased sales commission payments made in connection +with increased sales levels. +- 36 - +Table of Contents +General & Administrative +Increase in legal spending over the prior year, largely related to a foreign distributor matter, partially offset by a decrease in various +personnel related costs resulting in part from the death of our Executive Chairman during the fourth quarter of fiscal 2014. +Fiscal +2014 +Research & Development +Overall increase in spending on new product development activities, related primarily to the previously noted products for our +illumi gene molecular platform, as well as immunoassay products in development. +Selling & Marketing +Addition of field sales force and other personnel, including the filling of open territorial positions, along with increased product +sample expense. +General & Administrative +A decrease in bonus expense as a result of the previously noted decline in corporate-wide operating profits, partially offset by an approximate +$1,100 increase in stock-based compensation including $429 of stock-based compensation expense related to the accelerated vesting of certain stock-based awards held by our Executive Chairman at the time of his death in the fourth quarter of fiscal +2014, and other less significant general operating expense increases. +The amount of stock-based compensation expense reported for fiscal 2015, 2014 and +2013 was $3,324, $3,557 and $2,502, respectively. During fiscal 2012, we granted restricted share units and options to certain executive management employees to reward them for meeting Company revenue targets in advance of planned expectations. +These awards could only be earned if specified cumulative revenue thresholds were achieved, with the three measurement dates for ratably earning one-third of the grant being (i) the 21-month period ended June 30, 2013; (ii) the +33-month period ended June 30, 2014; and (iii) the 45-month period ended June 30, 2015. With the exception of the final tranche of these awards being held by our Executive Chairman at the time of his death in the fourth quarter of +fiscal 2014, no expense was recognized for these restricted share units and options, and as a result of none of the cumulative thresholds being met, all of these restricted share units and options granted have been cancelled. +During fiscal 2013 through fiscal 2015, we granted restricted share units to certain employees, generally with half of each employee’s grant being +time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings target for each respective fiscal year. Although dividend equivalents were +paid on these units throughout each of the respective fiscal years, because Meridian’s net earnings did not reach the minimum levels in any of these three fiscal years, the performance-based awards were not earned and no stock-based +compensation was recorded for the performance-based awards, except for those performance-based restricted share units being held by our Executive Chairman at the time of his death in the fourth quarter of fiscal 2014. +- 37 - +Table of Contents +Additionally, during fiscal 2015 in connection with the extension of an Amended and Restated Employment Agreement +we granted to our Chairman and Chief Executive Officer (i) restricted share units to be earned only if specified revenue and earnings per share targets were achieved for fiscal 2015; and (ii) time-vested options, with half vesting +September 30, 2015 and half vesting September 30, 2016. As a result of the fiscal 2015 performance targets being achieved, the restricted share units have been earned and the related compensation expense was recorded in fiscal 2015. +Operating Income +Operating income increased 7% and +decreased 9% in fiscal 2015 and 2014, respectively, as a result of the factors discussed above. +Other Income and Expense +In fiscal 2015, other income and expense included $1,100 of foreign currency losses, which related primarily to a foreign subsidiary intercompany loan being +marked-to-market. This compares to $300 of foreign currency losses in fiscal 2014. +Income Taxes +The effective rate for income taxes was 35%, 33% and 34% for fiscal 2015, 2014 and 2013, respectively. Our effective tax rate has ranged from 33% to 35% over +the last three fiscal years as a result of (i) increased apportionments in certain state taxing jurisdictions (2015); (ii) reversal of valuation allowances on net operating loss benefits in certain non-U.S. jurisdictions (2014); +(iii) net benefits on dividends from a non-U.S. subsidiary (2014); and (iv) the timing of renewal/expiration of the research and experimentation credit in the U.S. during this three year period. +In September 2013, the Internal Revenue Service issued Treasury Decision 9636, which enacted final tax regulations regarding the capitalization and expensing +of amounts paid to acquire, produce or improve tangible property. The regulations also include guidance regarding the retirement of depreciable property. Our adoption of these regulations on October 1, 2014 did not have a significant impact on +the Company’s consolidated results of operations, cash flows or financial position. +- 38 - +Table of Contents +Impact of Inflation +To the extent feasible, we have consistently followed the practice of adjusting our prices to reflect the impact of inflation on salaries and fringe benefits +for employees and the cost of purchased materials and services. Inflation and changing prices did not have a material adverse impact on our gross margin, revenues or operating income in fiscal 2015, 2014 or 2013. +Liquidity and Capital Resources: +Liquidity +Our cash flow and financing requirements are determined by analyses of operating and capital spending budgets, consideration of acquisition plans +and consideration of common share dividends. We have historically maintained a credit facility to augment working capital requirements and to respond quickly to acquisition opportunities. Our investment portfolio presently consists of overnight +repurchase agreements. +We have an investment policy that guides the holdings of our investment portfolio. Our objectives in managing the investment +portfolio are to (i) preserve capital; (ii) provide sufficient liquidity to meet working capital requirements and fund strategic objectives such as acquisitions; and (iii) capture a market rate of return commensurate with market +conditions and our policy’s investment eligibility criteria. As we look forward, we will continue to manage the holdings of our investment portfolio with preservation of capital being the primary objective. +We do not expect current conditions in the financial markets, or overall economic conditions, to have a significant impact on our liquidity needs, financial +condition or results of operations, although no assurances can be made in this regard. We intend to continue to fund our working capital requirements and dividends from current cash flows from operating activities and cash on hand. If needed, we +also have an additional source of liquidity through our $30,000 bank credit facility. Approximately $1,600 and $2,700 of our accounts receivable at September 30, 2015 and September 30, 2014, respectively, was due from Italian hospital +customers whose funding ultimately comes from the Italian government. In addition, the amount of our annual revenues in the country of Greece and the corresponding amount of customer receivables outstanding at any point in time is not significant, +and therefore, we do not expect any meaningful impact from the financial crisis in the country of Greece. Our liquidity needs may change if overall economic conditions worsen and/or liquidity and credit within the financial markets remains tight for +an extended period of time, and such conditions impact the collectibility of our customer accounts receivable or impact credit terms with our vendors, or disrupt the supply of raw materials and services. +- 39 - +Table of Contents +Fluctuations in overall stock market valuations may raise questions as to the potential impairment of goodwill +and other long-lived assets. Our annual goodwill impairment review takes place as of June 30 th each year, and is performed at the reporting unit level. There have been no impairments from +these annual reviews. As of September 30, 2015, our stock price was $17.10 per share, compared to our book value per share of $3.96 as of September 30, 2015. This relationship, stock price trading at a 4.3x multiple of book value, is an +indicator that the fluctuation in overall stock market valuations and its impact on our stock price has not been a triggering event for impairment of our goodwill and other long-lived assets. +During fiscal 2015, our overall cash position increased by approximately $7,000 to $50,000 at September 30, 2015. Net cash provided by operating +activities totaled $42,809 for fiscal 2015, a 12% increase over the $38,262 provided during fiscal 2014. This $4,547 increase results in large part from approximately $5,500 of incentive bonus payments related to fiscal 2013 being made in the first +quarter of fiscal 2014, with no such payments having been made during fiscal 2015. +Net cash flows from operating activities and cash on hand are +anticipated to be adequate to fund working capital requirements, capital expenditures and dividends during the next twelve months. During fiscal 2015, the per share amount of our cash dividend paid represented 94% of our diluted earnings per share, +exceeding our long-standing policy of establishing a cash dividend payout ratio between 75% and 85% of diluted earnings per share. Despite there being certain individual fiscal years in which our payout ratio has fallen outside of this policy range, +since adopting this policy in November 2002, our cumulative cash dividend payout has approximated 85% of cumulative net earnings during this timeframe. +Capital Resources +We have a $30,000 credit +facility with a commercial bank which expires April 21, 2018. As of November 23, 2015, there were no borrowings outstanding on this facility and we had 100% borrowing capacity available to us. We have had no borrowings outstanding under +this facility during fiscal 2015, 2014 or 2013. +Our capital expenditures are estimated to range between approximately $3,000 to $4,000 for fiscal 2016, +with the actual amount depending upon actual operating results and the phasing of certain projects. Such expenditures may be funded with cash and equivalents on hand, operating cash flows and/or availability under the $30,000 credit facility +discussed above. +During June 2015, we sold the land and building related to our former Life Science facility in Saco, Maine. Net proceeds from the sale +were approximately $1,138. +- 40 - +Table of Contents +Known Contractual Obligations: +Known contractual obligations and their related due dates were as follows as of September 30, 2015: +Total +Less than 1 +Year +1-3 Years +4-5 Years +More than +5 Years +Operating leases (1) +$ +4,143 +$ +1,632 +$ +2,422 +$ +89 +$ +— +Purchase obligations (2) +8,463 +8,226 +237 +— +— +Uncertain income tax positions liability and interest (3) +275 +275 +— +— +— +Total +$ +12,881 +$ +10,133 +$ +2,659 +$ +89 +$ +— +(1) +Meridian and its subsidiaries are lessees of (i) office and warehouse buildings in Ohio, Massachusetts, Florida, Australia, Belgium, France, Holland, Germany, Singapore, China and the U.K.; (ii) automobiles +for use by the diagnostic direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile machines and copier machines across all business units, under operating lease agreements that expire at various dates. +(2) +Meridian’s purchase obligations are primarily outstanding purchase orders for inventory and service items. These contractual commitments are not in excess of expected production requirements over the next twelve +months. +(3) +As of September 30, 2015, our liabilities for uncertain tax positions and related interest and penalties were $238 and $37, respectively. Due to inherent uncertainties in the timing of settlement of tax positions, +we are unable to estimate the timing of the effective settlement of these obligations. +Other Commitments and Off-Balance Sheet +Arrangements : +License Agreements +Meridian has entered into various license agreements that require payment of royalties based on a specified percentage of sales of related products (1% to +14%). Meridian expects that payments under these agreements will amount to approximately $4,000 in fiscal 2016. These royalty payments primarily relate to the Diagnostics segment. +Off-Balance Sheet Arrangements +Except for the +operating lease arrangements noted above, we have no off-balance sheet arrangements. +Market Risk Exposure : +Foreign Currency Risk +We have market risk exposure +related to foreign currency transactions from our operations outside the United States, as well as certain suppliers to our domestic businesses located outside the United States. The foreign currencies where we have market risk exposure are the +Australian dollar, the British pound, the Euro, and the Singapore dollar. Assessing foreign currency exposures is a component of our overall ongoing risk management process, with such currency risks managed as we believe appropriate. +- 41 - +Table of Contents +Concentration of Customers/Products Risk +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 37% of the segment’s total revenues or 28% of consolidated +revenues for fiscal 2015. Our C. difficile, foodborne, H. pylori , respiratory and women’s health & STD product families accounted for 79% of our Diagnostics segment’s third-party revenues during fiscal 2015, and 59% +of our fiscal 2015 consolidated revenues. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two diagnostics +manufacturing customers were 16% of the segment’s total revenues for fiscal 2015 or 4% of our fiscal 2015 consolidated revenues. Our Life Science segment has four other significant customers who purchase antigens, antibodies and reagents, which +together comprised 10% of the segment’s total revenues for fiscal 2015. +Critical Accounting Policies: +The consolidated financial statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally +accepted in the United States. Such accounting principles require management to make judgments about estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Management believes +that the following accounting policies are critical to understanding the accompanying consolidated financial statements because the application of such polices requires the use of significant estimates and assumptions, and the carrying values of +related assets and liabilities are material. +Revenue Recognition +Our revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue for the Diagnostics segment is reduced at +the date of sale for product price adjustments due certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, estimates of +inventories of certain of our products held by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. +Revenue for our Diagnostics segment includes revenue for our illumi gene molecular test system. This system includes an instrument, +instrument accessories and test kits. In markets where the test system is sold via multiple deliverable arrangements, the cost of the instrument and instrument accessories is deferred upon placement at a customer and amortized on a +straight-line basis into cost of sales over the expected utilization period, generally three years. +- 42 - +Table of Contents +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The significant +deliverables are an instrument, instrument accessories (e.g., printer) and test kits. An instrument and instrument accessories are delivered to the customer prior to the start of the customer utilization period, in order to accommodate customer +set-up and installation. There is de minimis consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are not a separate unit of accounting because such +equipment can only be used to process and read the results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test result), and therefore the instrument and +instrument accessories do not have standalone value to the customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the customer over the utilization period of +the instrument, which we estimate has a useful life of three years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue for the sale of test kits is recognized +upon shipment and transfer of title to the customers. +In markets where the test system is not sold via multiple deliverable arrangements, the cost of the +instrument and instrument accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of instruments and instrument accessories and test kits is recognized upon shipment and transfer +of title to the customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory the instruments, instrument accessories and test kits for resale to end-users. +Our products are generally not subject to a customer right of return except for product recall events under the rules and regulations of the Food and Drug +Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a loss was probable and estimable. +Life Science revenue for contract services may come from research and development services or manufacturing services, including process development work, or a +combination of both. Revenue is recognized based on each of the deliverables in a given arrangement having distinct and separate customer pricing. Depending on the nature of the arrangement, revenue is recognized as services are performed and +billed, upon completion and acceptance by the customer, or upon delivery of product and acceptance by the customer. +Inventories +Our inventories are carried at the lower of cost or market. Cost is determined on a first-in, first-out (FIFO) basis. We establish reserves against cost for +excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and other identified exposures. We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and +market conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. Such adjustments would negatively affect gross profit margin and overall results of operations. +- 43 - +Table of Contents +Intangible Assets +Our intangible assets include identifiable intangibles and goodwill. Identifiable intangibles include customer lists, supply agreements, manufacturing +technologies, patents, licenses and trade names. All of Meridian’s identifiable intangibles have finite lives. +Goodwill is subject to an annual +impairment review (or more frequently if impairment indicators arise). There have been no impairments from these analyses. +Identifiable intangibles with +finite lives are reviewed for impairment when events or circumstances indicate that such assets may not be recoverable at their current carrying value. Whether an event or circumstance triggers impairment is determined by comparing an estimate of +the asset’s undiscounted future cash flows to its carrying value. If impairment has occurred, it is measured by a fair-value based test. There were no events or circumstances in fiscal 2015, 2014 or 2013 indicating that the carrying value of +such assets may not be recoverable. +Our ability to recover intangible assets, both identifiable intangibles and goodwill, is dependent upon the future +cash flows of the related acquired businesses and assets. We are required to make judgments and assumptions regarding future cash flows, including sales levels, gross profit margins, operating expense levels, working capital levels, and capital +expenditures. With respect to identifiable intangibles, we also make judgments and assumptions regarding useful lives. +We consider the following factors +in evaluating events and circumstances for possible impairment: (i) significant under-performance relative to historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products +(related to specific identifiable intangibles); (iv) changes in overall business strategies; and (v) other factors. +If actual cash flows +decrease, this could trigger impairment of intangible assets and other long-lived assets. If impairment were to occur, this would negatively affect overall results of operations. +Income Taxes +Our provision for income taxes +includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting purposes and income for tax purposes. We prepare estimates of permanent and +temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, typically occurring in the third and fourth quarters of the current fiscal +year for the preceding fiscal year’s estimates. +- 44 - +Table of Contents +Our deferred tax assets include net operating loss carryforwards in foreign jurisdictions. The realization of tax +benefits related to net operating loss carryforwards is dependent upon the generation of future taxable income in the applicable jurisdictions. We assess the level of deferred tax asset valuation allowance needed, if any, by taking into +consideration historical and future projected operating results, future reversals of taxable temporary differences, and tax planning strategies. The amount of net deferred tax assets considered realizable could be reduced in future years if +estimates of future taxable income during the carryforward period are reduced. +Undistributed earnings in our non-U.S. subsidiaries are considered by us +to be permanently re-invested in such subsidiaries. Consequently, U.S. deferred tax liabilities on such earnings have not been recorded. +From time to +time, our tax returns in federal, state and foreign jurisdictions are examined by the applicable tax authorities. To the extent that adjustments result from the completion of these examinations or the lapsing of statutes of limitation, they will +affect tax liabilities in the period known. We believe that the results of any tax authority examinations would not have a significant adverse impact on our financial condition or results of operations. +In September 2013, the Internal Revenue Service issued Treasury Decision 9636, which enacted final tax regulations regarding the capitalization and expensing +of amounts paid to acquire, produce or improve tangible property. The regulations also include guidance regarding the retirement of depreciable property. Our adoption of these regulations on October 1, 2014 did not have a significant impact on +the Company’s consolidated results of operations, cash flows or financial position. +Recent Accounting Pronouncements: +In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which supersedes and replaces nearly all +currently-existing U.S. GAAP revenue recognition guidance including related disclosure requirements. This guidance will be effective for the Company beginning October 1, 2018 (fiscal 2019). The Company has not yet completed its assessment of +the impact that adoption of this guidance will have on its financial statements. +In September 2015, the FASB issued ASU No. 2015-16, +Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments , which amends currently-existing U.S. GAAP business combinations guidance. This guidance, which removes the requirement to retroactively apply +adjustments identified during the measurement period, will be effective for the Company beginning October 1, 2016 (fiscal 2017). We do not expect adoption of this guidance to have a significant impact on the Company’s consolidated results +of operations, cash flows or financial position. +- 45 - +Table of Contents +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +See Market Risk Exposure and Capital Resources under Item 7 above. +- 46 - +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements +Management’s Report on Internal Control over Financial Reporting +48 +Report of Independent Registered Public Accounting Firm +49 +Consolidated Statements of Operations for the years ended September 30, 2015, 2014 and 2013 +51 +Consolidated Statements of Comprehensive Income for the years ended September 30, 2015, 2014 and +2013 +52 +Consolidated Statements of Cash Flows for the years ended September 30, 2015, 2014 and 2013 +53 +Consolidated Balance Sheets as of September 30, 2015 and 2014 +54 +Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2015, 2014 and +2013 +56 +Notes to Consolidated Financial Statements +57 +Schedule No. II – Valuation and Qualifying Accounts for the years ended September +30, 2015, 2014 and 2013 +81 +All other supplemental schedules are omitted due to the absence of conditions under which they are required or because the +information is shown in the Consolidated Financial Statements or Notes thereto. +- 47 - +Table of Contents +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule +13a-15(f). +The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance +of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and +(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial +Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria in the 2013 Internal Control – Integrated Framework, issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Based on management’s evaluation and those criteria, the Company concluded that its system of internal control over financial reporting was effective as of September 30, 2015. +The Company’s independent registered public accounting firm has issued an attestation report on the registrant’s internal control over financial +reporting. +/s/ John A. Kraeutler +/s/ Melissa A. Lueke +John A. Kraeutler +Melissa A. Lueke +Chief Executive Officer +Executive Vice President and +November 30, 2015 +Chief Financial Officer +November 30, 2015 +- 48 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +We have audited the accompanying consolidated balance sheets of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the +“Company”) as of September 30, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, +2015. Our audits of the basic consolidated financial statements included the financial statement schedule listed in the index and appearing under Schedule No. II. We also have audited the Company’s internal control over financial reporting as +of September 30, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is +responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in +the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control +over financial reporting based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight +Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial +reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and +significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing +the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the +circumstances. We believe that our audits provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the +company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company +are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the financial statements. +- 49 - +Table of Contents +Because of its inherent limitations, internal control over financial reporting may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial +position of Meridian Bioscience, Inc. and subsidiaries as of September 30, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2015 in conformity with +accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in +all material respects, the information set forth therein. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2015, based on criteria established in the +2013 Internal Control—Integrated Framework issued by COSO. +/s/ GRANT THORNTON LLP +Cincinnati, Ohio +November 30, 2015 +- 50 - +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2015 +2014 +2013 +Net Revenues +$ +194,830 +$ +188,832 +$ +188,686 +Cost of Sales +72,948 +71,589 +67,642 +Gross Profit +121,882 +117,243 +121,044 +Operating Expenses: +Research and development +12,605 +12,552 +10,787 +Selling and marketing +25,601 +24,910 +22,424 +General and administrative +27,616 +27,389 +30,519 +Total operating expenses +65,822 +64,851 +63,730 +Operating Income +56,060 +52,392 +57,314 +Other Income (Expense): +Interest income +23 +25 +44 +Other, net +(1,020 +) +(309 +) +4 +Total other income (expense) +(997 +) +(284 +) +48 +Earnings Before Income Taxes +55,063 +52,108 +57,362 +Income Tax Provision +19,523 +17,365 +19,330 +Net Earnings +$ +35,540 +$ +34,743 +$ +38,032 +Earnings Per Share Data: +Basic earnings per common share +$ +0.85 +$ +0.84 +$ +0.92 +Diluted earnings per common share +$ +0.85 +$ +0.83 +$ +0.91 +Common shares used for basic earnings per common share +41,659 +41,455 +41,226 +Effect of dilutive stock options and restricted shares and units +353 +458 +669 +Common shares used for diluted earnings per common share +42,012 +41,913 +41,895 +Dividends declared per common share +$ +0.80 +$ +0.79 +$ +0.76 +Anti-dilutive Securities: +Common share options and restricted shares and units +551 +272 +254 +The accompanying notes are an integral part of these consolidated financial statements. +- 51 - +Table of Contents +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2015 +2014 +2013 +Net Earnings +$ +35,540 +$ +34,743 +$ +38,032 +Foreign currency translation adjustment +(2,639 +) +(436 +) +650 +Comprehensive Income +$ +32,901 +$ +34,307 +$ +38,682 +The accompanying notes are an integral part of these consolidated financial statements. +- 52 - +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2015 +2014 +2013 +Cash Flows From Operating Activities +Net earnings +$ +35,540 +$ +34,743 +$ +38,032 +Non-cash items included in net earnings: +Depreciation of property, plant and equipment +3,470 +3,523 +3,354 +Amortization of intangible assets +1,748 +2,039 +2,269 +Amortization of deferred illumi gene instrument costs +1,391 +1,702 +1,529 +Stock-based compensation +3,324 +3,557 +2,502 +Deferred income taxes +(122 +) +(140 +) +(1,823 +) +Loss on disposition and write-down of fixed assets and other assets +94 +6 +30 +Change in current assets +(6,079 +) +(1,528 +) +(3,486 +) +Change in current liabilities +3,238 +(5,996 +) +2,669 +Other, net +205 +356 +(640 +) +Net cash provided by operating activities +42,809 +38,262 +44,436 +Cash Flows From Investing Activities +Purchases of property, plant and equipment +(4,613 +) +(5,306 +) +(3,234 +) +Proceeds from sale of building +1,138 +— +— +Purchases of intangibles and other assets +(151 +) +(1,696 +) +(43 +) +Net cash used for investing activities +(3,626 +) +(7,002 +) +(3,277 +) +Cash Flows From Financing Activities +Dividends paid +(33,357 +) +(32,762 +) +(31,354 +) +Proceeds and tax benefits from exercises of stock options +2,614 +1,009 +2,752 +Net cash used for financing activities +(30,743 +) +(31,753 +) +(28,602 +) +Effect of Exchange Rate Changes on Cash and Equivalents +(1,514 +) +(742 +) +132 +Net Increase (Decrease) in Cash and Equivalents +6,926 +(1,235 +) +12,689 +Cash and Equivalents at Beginning of Period +43,047 +44,282 +31,593 +Cash and Equivalents at End of Period +$ +49,973 +$ +43,047 +$ +44,282 +Supplemental Cash Flow Information +Cash paid for income taxes +$ +20,168 +$ +19,952 +$ +20,093 +The accompanying notes are an integral part of these consolidated financial statements. +- 53 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2015 +2014 +Assets +Current Assets: +Cash and equivalents +$ +49,973 +$ +43,047 +Accounts receivable, less allowances of $248 in 2015 and $272 in 2014 +26,254 +23,232 +Inventories +35,817 +35,495 +Prepaid expenses and other current assets +7,378 +7,058 +Deferred income taxes +3,431 +3,916 +Total current assets +122,853 +112,748 +Property, Plant and Equipment, at Cost: +Land +986 +1,173 +Buildings and improvements +30,056 +29,146 +Machinery, equipment and furniture +41,541 +40,192 +Construction in progress +1,139 +652 +Subtotal +73,722 +71,163 +Less: accumulated depreciation and amortization +46,230 +43,553 +Net property, plant and equipment +27,492 +27,610 +Other Assets: +Goodwill +22,349 +23,193 +Other intangible assets, net +5,931 +7,813 +Restricted cash +1,000 +1,000 +Deferred illumi gene instrument costs, net +1,750 +2,740 +Deferred income taxes +1,523 +1,483 +Other assets +384 +342 +Total other assets +32,937 +36,571 +Total assets +$ +183,282 +$ +176,929 +The accompanying notes are an +integral part of these consolidated financial statements. +- 54 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2015 +2014 +Liabilities and Shareholders’ Equity +Current Liabilities: +Accounts payable +$ +6,646 +$ +4,966 +Accrued employee compensation costs +5,132 +4,761 +Other accrued expenses +2,587 +3,149 +Income taxes payable +886 +859 +Total current liabilities +15,251 +13,735 +Non-Current Liabilities +2,158 +2,165 +Commitments and Contingencies +Shareholders’ Equity: +Preferred stock, no par value; 1,000,000 shares authorized; none issued +— +— +Common shares, no par value; 71,000,000 shares authorized; 41,838,399 and 41,622,216 issued, respectively +— +— +Additional paid-in capital +117,151 +111,851 +Retained earnings +51,052 +48,869 +Accumulated other comprehensive income (loss) +(2,330 +) +309 +Total shareholders’ equity +165,873 +161,029 +Total liabilities and shareholders’ equity +$ +183,282 +$ +176,929 +The accompanying notes are an integral part of these consolidated financial statements. +- 55 - +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (dollars and shares in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +Common +Shares +Issued +Additional +Paid-in +Capital +Retained +Earnings +Accum Other +Comp +Income +(Loss) +Total +Balance at September 30, 2012 +41,284 +$ +102,443 +$ +40,210 +$ +95 +$ +142,748 +Cash dividends paid - $0.76 per share +— +— +(31,354 +) +— +(31,354 +) +Exercise of stock options +226 +2,564 +— +— +2,564 +Conversion of restricted stock units +8 +— +— +— +— +Stock compensation expense +— +2,405 +— +— +2,405 +Net earnings +— +— +38,032 +— +38,032 +Foreign currency translation adjustment +— +— +— +650 +650 +Balance at September 30, 2013 +41,518 +107,412 +46,888 +745 +155,045 +Cash dividends paid - $0.79 per share +— +— +(32,762 +) +— +(32,762 +) +Exercise of stock options +78 +882 +— +— +882 +Issuance of restricted shares, net of forfeitures +(1 +) +— +— +— +— +Conversion of restricted stock units +27 +— +— +— +— +Stock compensation expense +— +3,557 +— +— +3,557 +Net earnings +— +— +34,743 +— +34,743 +Foreign currency translation adjustment +— +— +— +(436 +) +(436 +) +Balance at September 30, 2014 +41,622 +111,851 +48,869 +309 +161,029 +Cash dividends paid - $0.80 per share +— +— +(33,357 +) +— +(33,357 +) +Exercise of stock options +187 +1,976 +— +— +1,976 +Conversion of restricted stock units +29 +— +— +— +— +Stock compensation expense +— +3,324 +— +— +3,324 +Net earnings +— +— +35,540 +— +35,540 +Foreign currency translation adjustment +— +— +— +(2,639 +) +(2,639 +) +Balance at September 30, 2015 +41,838 +$ +117,151 +$ +51,052 +$ +(2,330 +) +$ +165,873 +The accompanying notes are an integral part of these consolidated financial statements. +- 56 - +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +Meridian Bioscience, Inc. and Subsidiaries +(dollars +and shares in thousands, except per share data) +(1) +Summary of Significant Accounting Policies +(a) +Nature of Business - Meridian is a fully-integrated life science company whose principal businesses are (i) the development, manufacture and distribution of diagnostic test kits primarily for certain +gastrointestinal, viral, respiratory and parasitic infectious diseases; (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other +diagnostic manufacturers; and (iii) the contract development and manufacture of proteins and other biologicals for use by biopharmaceutical and biotechnology companies engaged in research for new drugs and vaccines. +(b) +Principles of Consolidation - The consolidated financial statements include the accounts of Meridian Bioscience, Inc. and its subsidiaries. All intercompany accounts and transactions have been eliminated. Unless +the context requires otherwise, references to “Meridian,” “we,” “us,” “our” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +(c) +Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of +assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. +(d) +Foreign Currency Translation - Assets and liabilities of foreign operations are translated using year-end exchange rates with gains or losses resulting from translation included as a separate component of +accumulated other comprehensive income or loss. Revenues and expenses are translated using exchange rates prevailing during the year. We also recognize foreign currency transaction gains and losses on certain assets and liabilities that are +denominated in the Australian dollar, British pound, Euro and Singapore dollar currencies. These gains and losses are included in other income and expense in the accompanying consolidated statements of operations. Included within other income and +expense in the consolidated statements of operations for the year ending September 30, 2015 is $1,174 in currency losses related to a foreign subsidiary intercompany loan being marked-to-market. +- 57 - +Table of Contents +(e) +Cash, Cash Equivalents and Investments - The primary objectives of our investment activities are to preserve capital and provide sufficient liquidity to meet operating requirements and fund strategic initiatives +such as acquisitions. We maintain a written investment policy that governs the management of our investments in fixed income securities. This policy, among other things, provides that we may purchase only high credit-quality securities that have +short-term ratings of at least A-2, P-2 and F-2 or better, and long-term ratings of at least A, Baa1 and A or better, by Standard & Poor’s, Moody’s and Fitch, respectively, at the time of purchase. We consider short-term +investments with original maturities of 90 days or less to be cash equivalents, including overnight repurchase agreements and institutional money market funds. At times our investments of cash and equivalents with various high credit quality +financial institutions may be in excess of the Federal Deposit Insurance Corporation (FDIC) insurance limit. +Our investment +portfolio includes the following components: +September 30, 2015 +September 30, 2014 +Cash and +Equivalents +Other +Cash and +Equivalents +Other +Overnight repurchase agreements +$ +25,436 +$ +— +$ +26,407 +$ +— +Cash on hand – +Restricted +— +1,000 +— +1,000 +Unrestricted +24,537 +— +16,640 +— +Total +$ +49,973 +$ +1,000 +$ +43,047 +$ +1,000 +(f) +Inventories - Inventories are stated at the lower of cost or market. Cost is determined on a first-in, first-out (FIFO) basis. +illumi gene ® instruments are carried in inventory until customer placement, at which time they are transferred to deferred illumi gene instrument costs, +unless sold outright. +We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life +may expire before sale to customers, and other identified exposures. Such reserves were $2,456 and $2,942 at September 30, 2015 and 2014, respectively. We estimate these reserves based on assumptions about future demand and market conditions. +If actual demand and market conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. Such adjustments would negatively affect gross profit margin and overall +results of operations. +(g) +Property, Plant and Equipment - Property, plant and equipment are stated at cost. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed +from the accounts and the resulting gain or loss is reflected in earnings. Maintenance and repairs are expensed as incurred. Depreciation is computed on the straight-line method in amounts sufficient to write-off the cost over the estimated useful +lives, generally as follows: +Buildings and improvements - 18 to 40 years +Machinery, equipment and furniture - 3 to 10 years +Computer equipment and software - 3 to 5 years +- 58 - +Table of Contents +(h) +Intangible Assets - Goodwill is subject to an annual impairment review (or more frequently if impairment indicators arise) by first performing a qualitative assessment to determine whether it is more likely than +not that the fair value of a reporting unit is less than its carrying value. In the event that a reporting unit does not pass the qualitative assessment, the reporting unit’s carrying value is compared to its fair value, with fair value of the +reporting unit estimated using market and discounted cash flow approaches. Goodwill is considered impaired if the carrying value of the reporting unit exceeds its fair value. We perform our annual impairment review as of June 30, the end of our +third fiscal quarter. We have no intangible assets with indefinite lives other than goodwill. There have been no impairments from these analyses for fiscal 2015, 2014 or 2013. +The change in goodwill was a decrease of $844 in fiscal 2015 and an increase of $78 in fiscal 2014. Both years reflect the effect of the Life +Science segment’s Bioline Group and the currency translation adjustments thereon. +A summary of Meridian’s acquired intangible +assets subject to amortization, as of September 30, 2015 and 2014 is as follows. +2015 +2014 +As of September 30, +Gross +Carrying +Value +Accum. +Amort. +Gross +Carrying +Value +Accum. +Amort. +Manufacturing technologies, core products and cell lines +$ +11,582 +$ +10,906 +$ +11,685 +$ +10,568 +Trademarks, licenses and patents +6,410 +3,296 +6,463 +2,766 +Customer lists and supply agreements +12,105 +9,964 +12,378 +9,379 +$ +30,097 +$ +24,166 +$ +30,526 +$ +22,713 +During fiscal 2014, we acquired the remaining licensing rights related to patents that are part of our +illumi gene molecular technology for $1,638. These rights are being amortized over a weighted average period of approximately 8.5 years. +The actual aggregate amortization expense for these intangible assets for fiscal 2015, 2014 and 2013 was $1,748, $2,039 and $2,269, +respectively. The estimated aggregate amortization expense for these intangible assets for each of the five succeeding fiscal years is as follows: fiscal 2016 - $1,411, fiscal 2017 - $1,116, fiscal 2018 - $1,095, fiscal 2019 - $1,054 and fiscal 2020 +- $880. +Long-lived assets, excluding goodwill, are reviewed for impairment when events or circumstances indicate that such assets may not +be recoverable at their carrying value. Whether an event or circumstance triggers an impairment is determined by comparing an estimate of the asset’s future undiscounted cash flows to its carrying value. If impairment has occurred, it is +measured by a fair-value based test. +- 59 - +Table of Contents +Our ability to recover the carrying value of our intangible assets, both identifiable intangibles +and goodwill, is dependent upon the future cash flows of the related acquired businesses and assets. We make judgments and assumptions regarding future cash flows, including sales levels, gross profit margins, operating expense levels, working +capital levels, and capital expenditures. With respect to identifiable intangibles and fixed assets, we also make judgments and assumptions regarding useful lives. +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant under-performance +relative to historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; and +(v) other factors. +If actual cash flows are less favorable than projections, this could trigger impairment of intangible assets and +other long-lived assets. If impairment were to occur, this would negatively affect overall results of operations. No triggering events have been identified by the Company for fiscal 2015, 2014 or 2013. +(i) +Revenue Recognition and Accounts Receivable - Revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue for the Diagnostics segment is reduced at the date of +sale for product price adjustments due certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, estimates of inventories of +certain of our products held by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. Such accruals were $5,581 at September 30, 2015 and $4,220 at +September 30, 2014, and have been netted against accounts receivable. +Revenue for our Diagnostics segment includes +revenue for our illumi gene molecular test system. This system includes an instrument, instrument accessories and test kits. In markets where the test system is sold via multiple deliverable arrangements, the cost of +the instrument and instrument accessories is deferred upon placement at a customer and amortized on a straight-line basis into cost of sales over the expected utilization period, generally three years. +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The significant deliverables are an instrument, +instrument accessories (e.g., printer) and test kits. An instrument and instrument accessories are delivered to the customer prior to the start of the customer utilization period, in order to accommodate customer set-up and installation. There is +de minimis consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are not a separate unit of accounting because such equipment can only be used to +process and read the results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test result), and therefore the instrument and instrument accessories do not have +standalone value to the customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the customer over the utilization period of the instrument, which we estimate has +a useful life of three years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue for the sale of test kits is recognized upon shipment and transfer of title +to the customers. +- 60 - +Table of Contents +In markets where the test system is not sold via multiple deliverable arrangements, the cost of +the instrument and instrument accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of instruments and instrument accessories and test kits is recognized upon shipment and +transfer of title to the customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory the instruments, instrument accessories and test kits for resale to end-users. +Our products are generally not subject to a customer right of return except for product recall events under the rules and regulations of the +Food and Drug Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a loss was probable and estimable. +Life Science revenue for contract services may come from research and development services or manufacturing services, including process +development work, or a combination of both. Revenue is recognized based on each of the deliverables in a given arrangement having distinct and separate customer pricing. Depending on the nature of the arrangement, revenue is recognized as services +are performed and billed, upon completion and acceptance by the customer, or upon delivery of product and acceptance by the customer. +Trade accounts receivable are recorded in the accompanying consolidated balance sheets at invoiced amounts less provisions for distributor +price adjustments under local contracts and doubtful accounts. The allowance for doubtful accounts represents our estimate of probable credit losses and is based on historical write-off experience and known conditions that would likely lead to +non-payment. The allowance for doubtful accounts and related metrics, such as days’ sales outstanding, are reviewed monthly. Accounts with past due balances over 90 days are reviewed individually for collectibility. Customer invoices are +charged off against the allowance when we believe it is probable that the invoices will not be paid. +(j) +Research and Development Costs - Research and development costs are charged to expense as incurred. Research and development costs include, among other things, salaries and wages for research scientists, +materials and supplies used in the development of new products, costs for development of instrumentation equipment, costs for clinical trials, and costs for facilities and equipment. +- 61 - +Table of Contents +(k) +Income Taxes - The provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting +and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, typically +occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +We account for uncertain tax positions using a benefit recognition model with a two-step approach: (i) a more-likely-than-not recognition +criterion; and (ii) a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the +benefit will be sustained on its technical merits, no benefit is recorded. We recognize accrued interest related to unrecognized tax benefits as a portion of our income tax provision in the consolidated statements of operations. See Note 4. +(l) +Stock-Based Compensation - We recognize compensation expense for all share-based awards made to employees, based upon the fair value of the share-based award on the date of the grant. See Note 5(b). +(m) +Comprehensive Income (Loss) - Comprehensive income (loss) represents the net change in shareholders’ equity during a period from sources other than transactions with shareholders. As reflected in the +accompanying consolidated statements of comprehensive income, our comprehensive income or loss is comprised of net earnings and foreign currency translation. +(n) +Shipping and Handling Costs - Shipping and handling costs invoiced to customers are included in net revenues. Costs to distribute products to customers, including freight costs, warehousing costs, and other +shipping and handling activities are included in cost of sales. +(o) +Non-Income Government-Assessed Taxes - We classify all non-income, government-assessed taxes (sales, use and value-added) collected from customers and remitted by us to appropriate revenue authorities, on a net +basis (excluded from net revenues) in the accompanying consolidated statements of operations. +(p) +Recent Accounting Pronouncements - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes and replaces nearly all currently-existing U.S. GAAP revenue +recognition guidance including related disclosure requirements. This guidance will be effective for the Company beginning October 1, 2018 (fiscal 2019). The Company has not yet completed its assessment of the impact that adoption of this +guidance will have on its financial statements. +(q) +Reclassifications - Certain reclassifications have been made to the prior fiscal year financial statements to conform to the current year presentation. Such reclassifications had no impact on net earnings or +shareholders’ equity. +- 62 - +Table of Contents +(2) +Inventories +Inventories are comprised of the following: +As of September 30, +2015 +2014 +Raw materials +$ +7,095 +$ +5,674 +Work-in-process +10,096 +10,591 +Finished goods - illumi gene instruments +1,890 +1,710 +Finished goods - kits and reagents +16,736 +17,520 +Total +$ +35,817 +$ +35,495 +(3) +Bank Credit Arrangements +We have a $30,000 credit facility with a commercial bank, which expires in April 2018. This credit facility is collateralized by our +business assets, except for those of non-U.S. subsidiaries, which totaled approximately $156,000 at September 30, 2015. There were no borrowings outstanding on this credit facility at September 30, 2015 or September 30, 2014. +Available borrowings under this credit facility were $30,000 at September 30, 2015 and September 30, 2014. In connection with this bank credit facility, we are required to comply with financial covenants that limit the amount of debt +obligations and require a minimum amount of tangible net worth. We are in compliance with all covenants. We are also required to maintain a cash compensating balance with the bank in the amount of $1,000, pursuant to this bank credit facility and +are in compliance with this requirement. +- 63 - +Table of Contents +(4) +Income Taxes +(a) +Earnings before income taxes, and the related provision for income taxes for the years ended September 30, 2015, 2014 and 2013 were as follows: +Year Ended September 30, +2015 +2014 +2013 +Domestic +$ +50,653 +$ +48,350 +$ +53,963 +Foreign +4,410 +3,758 +3,399 +Total earnings before income taxes +$ +55,063 +$ +52,108 +$ +57,362 +Provision (credit) for income taxes - +Federal - +Current +$ +16,152 +$ +15,021 +$ +18,311 +Temporary differences +Fixed asset basis differences and depreciation +50 +108 +121 +Intangible asset basis differences and amortization +(421 +) +(210 +) +(339 +) +Currently non-deductible expenses and reserves +217 +50 +(425 +) +Stock-based compensation +126 +59 +(282 +) +Tax credit carryforwards +250 +225 +(717 +) +Other, net +19 +66 +43 +Subtotal +16,393 +15,319 +16,712 +State and local +2,236 +1,762 +2,013 +Foreign +894 +284 +605 +Total income tax provision +$ +19,523 +$ +17,365 +$ +19,330 +(b) +The following is a reconciliation between the statutory U.S. income tax rate and the effective rate derived by dividing the provision for income taxes by earnings before income taxes: +Year Ended September 30, +2015 +2014 +2013 +Computed income taxes at statutory rate +$ +19,264 +35.0 +% +$ +18,238 +35.0 +% +$ +20,078 +35.0 +% +Increase (decrease) in taxes resulting from - +State and local income taxes +1,365 +2.5 +1,061 +2.0 +1,270 +2.2 +Net benefit on foreign dividend +— +— +(274 +) +(0.5 +) +(84 +) +(0.2 +) +Foreign tax rate differences +(217 +) +(0.4 +) +(430 +) +(0.8 +) +(18 +) +— +Qualified domestic production incentives +(1,197 +) +(2.2 +) +(1,175 +) +(2.3 +) +(1,621 +) +(2.8 +) +Other, net +308 +0.6 +(55 +) +(0.1 +) +(295 +) +(0.5 +) +$ +19,523 +35.5 +% +$ +17,365 +33.3 +% +$ +19,330 +33.7 +% +- 64 - +Table of Contents +(c) +The components of net deferred tax assets were as follows: +As of September 30, +2015 +2014 +Deferred tax assets - +Valuation reserves and non-deductible expenses +$ +1,931 +$ +1,984 +Stock compensation expense not deductible +3,221 +3,328 +Net operating loss carryforwards +348 +544 +Tax credit carryforwards +242 +492 +Inventory basis differences +1,186 +1,340 +Other +8 +8 +Subtotal +6,936 +7,696 +Less valuation allowance +(15 +) +(8 +) +Deferred tax assets +6,921 +7,688 +Deferred tax liabilities - +Fixed asset basis differences and depreciation +(995 +) +(951 +) +Intangible asset basis differences and amortization +(972 +) +(1,338 +) +Deferred tax liabilities +(1,967 +) +(2,289 +) +Net deferred tax assets +$ +4,954 +$ +5,399 +For income tax purposes, we have tax benefits related to operating loss carryforwards in the countries of Australia, Belgium +and Singapore, which have no expiration date, on which we have recorded deferred tax assets. We also have tax benefits related to tax credit carryforwards in the U.S., which expire in fiscal 2022, on which we have recorded deferred tax assets. +The realization of deferred tax assets in foreign jurisdictions is dependent upon the generation of future taxable income in these countries. We have +considered the levels of currently anticipated pre-tax income in foreign jurisdictions in assessing the required level of the deferred tax asset valuation allowance. Taking into consideration historical and current operating results, and other +factors, we believe that it is more likely than not that the net deferred tax asset for foreign jurisdictions will be realized except for Singapore, for which a full valuation allowance has been recorded. The amount of the net deferred tax asset +considered realizable in foreign jurisdictions, however, could be reduced in future years if estimates of future taxable income during the carryforward period are reduced. +Undistributed earnings reinvested indefinitely in our non-U.S. operations were approximately $10,000 and $8,000 at September 30, 2015 and +September 30, 2014, respectively. U.S. deferred tax liabilities of approximately $1,800 and $1,300 on such earnings, after consideration of foreign tax credits, have not been recorded as of September 30, 2015 and September 30, 2014, +respectively. +As described in Note 1, we utilize a comprehensive model for the recognition, measurement, presentation and disclosure of uncertain tax +positions, assuming full knowledge of all relevant facts by the applicable tax authorities. The total amount of unrecognized tax benefits at September 30, 2015 and September 30, 2014 related to such positions was $275 and $372, +respectively, of which the full amounts would favorably affect the effective tax rate if recognized. We recognize interest and penalties related to uncertain tax positions as a component of our income tax provision. During fiscal 2015 we decreased +our tax provision by approximately $19 for such interest and penalties, while during fiscal 2014 they resulted in an approximate $26 increase in our tax provision. We had approximately $37 accrued for the payment of interest and penalties at +September 30, 2015 compared to $56 accrued at September 30, 2014. The amount of our liability for uncertain tax positions expected to be paid or settled in the next 12 months is uncertain. +- 65 - +Table of Contents +A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: +2015 +2014 +Unrecognized income tax benefits beginning of year +$ +372 +$ +208 +Additions for tax positions related to the current year +— +11 +Additions for tax positions of prior years +9 +153 +Reductions for tax positions of prior years +(28 +) +— +Tax examination and other settlements +(78 +) +— +Unrecognized income tax benefits at end of year +$ +275 +$ +372 +We are subject to examination by the tax authorities in the U.S. (both federal and state) and the countries of Australia, +Belgium, China, England, France, Germany, Holland, Italy and Singapore. In the U.S., open tax years are for fiscal 2012, fiscal 2013 and fiscal 2014. In countries outside the U.S., open tax years generally range from fiscal 2010 and forward. +However, in Australia, Belgium and Singapore, the utilization of local net operating loss carryforwards extends the statute of limitations for examination well into the foreseeable future. +(5) +Employee Benefits +(a) +Savings and Investment Plan - We have a profit sharing and retirement savings plan covering substantially all full-time U.S. employees. Profit sharing contributions to the plan, which are discretionary, are +approved by the board of directors. The plan permits participants to contribute to the plan through salary reduction. Under terms of the plan, we match 50% of an employee’s contributions, up to a maximum match of 3% of eligible compensation. +Our discretionary and matching contributions to the plan amounted to approximately $1,567, $1,542 and $1,539, during fiscal 2015, 2014 and 2013, respectively. +(b) +Stock-Based Compensation Plans - During fiscal 2015, we had two active stock-based compensation plans, the 2004 Equity Compensation Plan, which became effective December 7, 2004, as amended (the “2004 +Plan”) and the 2012 Stock Incentive Plan, which became effective January 25, 2012 (the “2012 Plan”). In addition, we have an Employee Stock Purchase Plan (the “ESP Plan”), which became effective October 1, 1997. +Under the ESP Plan, we sell shares of stock to our full-time and part-time employees up to the number of shares equivalent to a 1% to 15% payroll deduction from an employee’s base salary plus an additional 5% dollar match of this deduction by +Meridian. +- 66 - +Table of Contents +Each of the 2004 Plan and 2012 Plan authorized the granting of new shares for options, restricted +shares or restricted share units for up to 3,000 shares, with the non-granted portion of the 2004 Plan permitted to be carried forward and added to the 2012 Plan authorized limit. As of September 30, 2015, we have granted 1,503 and 903 shares +under the 2004 Plan and 2012 Plan, respectively, thereby resulting in a remaining authorized limit of 3,594 shares. Options may be granted at exercise prices not less than 100% of the closing market value of the underlying common shares on the date +of grant and have maximum terms up to ten years. Vesting schedules for options, restricted shares and restricted share units are established at the time of grant and may be set based on future service periods, achievement of performance targets or a +combination thereof. All options contain provisions restricting their transferability and limiting their exercise in the event of termination of employment or the disability or death of the optionee. We recognize compensation expense for all +share-based payments made to employees, based upon the fair value of the share-based payment on the date of the grant. +During fiscal 2012, +we granted approximately 110 restricted share units (with a grant date fair value of $17.57 per share) and 1,035 options (with a weighted-average grant date fair value of $4.66 per option) to certain executive management employees to incentivize the +achievement of Company revenue targets in advance of planned expectations. These awards could only be earned if specified cumulative revenue thresholds were achieved, with the three measurement dates for ratably earning one-third of the grant being +(i) the 21-month period ended June 30, 2013; (ii) the 33-month period ended June 30, 2014; and (iii) the 45-month period ended June 30, 2015. With the exception of the final tranche of these awards being held by our +Executive Chairman at the time of his death in the fourth quarter of fiscal 2014, no expense was recognized for these restricted share units and options, and as a result of none of the cumulative thresholds being met, these restricted share units +and options have been cancelled. +During fiscal 2013, we granted approximately 204 restricted share units (with a weighted-average grant +date fair value of $19.38 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject +to attainment of a specified earnings target for fiscal 2013. While dividend equivalents were paid on these units throughout fiscal 2013, the target for fiscal 2013 was not met and the performance-based portion of the restricted share units granted +during fiscal 2013 have been cancelled. +During fiscal 2014, we granted approximately 270 restricted share units (with a weighted-average +grant date fair value of $24.82 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being +subject to attainment of a specified earnings target for fiscal 2014. While dividend equivalents were paid on these units throughout fiscal 2014, the target for fiscal 2014 was not met and, with the exception of these awards being held by our +Executive Chairman at the time of his death in the fourth quarter of fiscal 2014, the performance-based portion of the restricted share units granted during fiscal 2014 have been cancelled. +- 67 - +Table of Contents +Similar to previous years, during fiscal 2015, we granted approximately 270 restricted share +units (with a weighted-average grant date fair value of $17.91 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, +and the remaining half being subject to attainment of a specified earnings target for fiscal 2015. While dividend equivalents were paid on these units throughout fiscal 2015, the target for fiscal 2015 was not met and the performance-based portion +of these restricted share units granted during fiscal 2015 have been cancelled. +Additionally, during fiscal 2015 in connection with the +extension of an Amended and Restated Employment Agreement, we granted to our Chairman and Chief Executive Officer (i) 25 restricted share units (with a grant date fair value of $16.50 per share) to be earned only if specified revenue and +earnings per share targets were achieved for fiscal 2015; and (ii) 100 time-vested options (with a weighted-average grant date fair value of $3.73 per share, as included in the options table below), with half vesting September 30, 2015 and +half vesting September 30, 2016. As a result of the fiscal 2015 performance targets being achieved, the restricted share units have been earned and the related compensation expense recorded in fiscal 2015. +Giving effect to these grants, cancellations and certain other activities for restricted shares and restricted share units throughout the +years, including conversions to common shares, forfeitures, and new hire and employee promotion grants, approximately 440 restricted share units remain outstanding as of September 30, 2015, with a weighted-average grant date fair value of +$19.76 per share, a weighted-average remaining vesting period of 1.68 years and an aggregate intrinsic value of $7,466. The weighted-average grant date fair value of the approximate 75 restricted shares and units that vested during fiscal 2015 was +$22.90 per share. +The amount of stock-based compensation expense reported was $3,324, $3,557 and $2,502 in fiscal 2015, 2014 and 2013, +respectively. The fiscal 2015 expense is comprised of $591 related to stock options and $2,733 related to restricted shares and units; the fiscal 2014 expense is comprised of $486 related to stock options and $3,071 related to restricted shares and +units; and the fiscal 2013 expense is comprised of $336 related to stock options, $2,069 related to restricted shares and units, and $97 related to the granting of unrestricted common shares to two executive officers. The total income tax benefit +recognized in the income statement for these stock-based compensation arrangements was $1,250, $1,185 and $850, for fiscal 2015, 2014 and 2013, respectively. As of September 30, 2015, we expect future stock compensation expense for unvested +options and unvested restricted stock units to total $277 and $2,029, respectively, which will be recognized during fiscal years 2016 through 2019. +- 68 - +Table of Contents +We recognize compensation expense only for the portion of shares that we expect to vest. As such, +we apply estimated forfeiture rates to our compensation expense calculations. These rates have been derived using historical forfeiture data, stratified by several employee groups. During fiscal 2015, 2014 and 2013, we recorded $86, $108 and $93, +respectively, in stock compensation expense to adjust estimated forfeiture rates to actual. +We have elected to use the Black-Scholes +option pricing model to determine grant-date fair value for stock options, with the following assumptions: (i) expected share price volatility based on the average of Meridian’s historical volatility over the options’ expected lives +and implied volatility based on the value of tradable call options; (ii) expected life of options based on contractual lives, employees’ historical exercise behavior and employees’ historical post-vesting employment termination +behavior; (iii) risk-free interest rates based on treasury rates that correspond to the expected lives of the options; and (iv) dividend yield based on the expected yield on underlying Meridian common stock. +Year ended September 30, +2015 +2014 +2013 +Risk-free interest rates +2.07 +% +1.80% +0.88% +Dividend yield +3.7 +% +3.5% +4.1% +Life of option +6.33 yrs. +6.29 yrs. +6.23 yrs. +Share price volatility +33 +% +33% +36% +Forfeitures (by employee group) +0%-15 +% +0%-14% +0%-10% +A summary of the status of our stock option plans at September 30, 2015 and changes during the year is +presented in the table and narrative below: +Options +Wtd Avg +Exercise +Price +Wtd Avg +Remaining +Life (Yrs) +Aggregate +Intrinsic +Value +Outstanding beginning of period +1,142 +$ +19.11 +Grants +247 +17.48 +Exercises +(187 +) +13.28 +Forfeitures +(12 +) +20.11 +Cancellations +(374 +) +17.78 +Outstanding end of period +816 +$ +20.54 +4.86 +$ +341 +Exercisable end of period +677 +$ +20.98 +4.02 +$ +308 +- 69 - +Table of Contents +A summary of the status of our nonvested options as of September 30, 2015, and changes +during the year ended September 30, 2015, is presented below: +Options +Weighted- +Average +Grant Date +Fair Value +Nonvested beginning of period +360 +$ +4.78 +Granted +247 +3.95 +Vested +(131 +) +4.36 +Forfeitures +(1 +) +5.03 +Cancelled +(336 +) +4.58 +Nonvested end of period +139 +$ +4.18 +The weighted average grant-date fair value of options granted was $3.95, $5.48 and $4.19 for fiscal 2015, 2014 +and 2013, respectively. The total intrinsic value of options exercised was $850, $1,110 and $2,483, for fiscal 2015, 2014 and 2013, respectively. The total grant-date fair value of options that vested during fiscal 2015, 2014 and 2013 was $571, $701 +and $712, respectively. +Cash received from options exercised was $2,478, $567 and $2,258 for fiscal 2015, 2014 and 2013, respectively. Tax +(expense) benefits recorded to additional paid-in capital from option exercises totaled ($502), $315 and $306 for fiscal 2015, 2014 and 2013, respectively. +(6) +Non-Current Liabilities +The Company and its Chairman and Chief Executive Officer are parties to an employment agreement and a supplemental benefit agreement, under +which we are obligated to provide certain post-retirement benefits. These obligations total $1,399 and $1,247 at September 30, 2015 and September 30, 2014, respectively. In addition, we are required by the governments of certain of the +foreign countries in which we operate to maintain a level of reserves for potential future severance indemnity. These reserves total $668 and $831 at September 30, 2015 and September 30, 2014, respectively. +(7) +Reportable Segments and Major Concentration Data +Our reportable segments are Diagnostics and Life Science, with segmentation between the two determined based upon the nature of products and +the types of customers. The Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, and the sale and distribution of diagnostic test kits domestically and abroad. The Life Science segment consists of manufacturing operations in +Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically +and abroad, including sales and business development offices in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. The Life Science segment also includes the contract development and manufacture of cGMP clinical +grade proteins and other biologicals for use by biopharmaceutical and biotechnology companies engaged in research for new drugs and vaccines. +- 70 - +Table of Contents +Revenues from individual customers constituting 10% or more of consolidated net revenues are as follows: +Year Ended September 30, +2015 +2014 +2013 +Customer A +$ +29,155 +(15 +)% +$ +28,278 +(15 +)% +$ +35,082 +(19 +)% +Customer B +$ +25,276 +(13 +)% +$ +22,780 +(12 +)% +$ +25,457 +(13 +)% +Accounts receivable from these two Diagnostics distributor customers accounted for 21% and 15% of consolidated accounts +receivable at September 30, 2015 and September 30, 2014, respectively. The Company’s international revenues totaled $52,313, $57,051, and $56,224 in fiscal years 2015, 2014 and 2013, respectively. Our diagnostic focus product families +– C. difficile, foodborne, H. pylori , respiratory and women’s health & STD – accounted for 59%, 58% and 59% of consolidated net revenues in fiscal 2015, 2014 and 2013, respectively. We currently sole-source from +a U.S. manufacturer the illumi pro -10 ™ instrument on which our illumi gene molecular testing platform operates. Additionally, two of our foodborne products sourced from another vendor +accounted for 14% of third-party revenues for our Diagnostics segment in each of fiscal 2015, 2014 and 2013. +Significant revenue information by +country for the Diagnostics and Life Science segments is as follows. Revenues are attributed to the geographic area based on the location to which the product is delivered. +Year Ended September 30, +2015 +2014 +2013 +United States +$ +120,599 +$ +112,917 +$ +114,935 +Italy +7,090 +8,469 +7,427 +Japan +2,603 +2,097 +3,937 +United Kingdom +1,964 +1,942 +2,141 +France +1,603 +1,841 +1,936 +Holland +1,326 +1,613 +1,764 +Canada +1,315 +1,359 +1,248 +Belgium +1,289 +1,241 +1,285 +Other countries +8,325 +10,021 +9,956 +Total Diagnostics +$ +146,114 +$ +141,500 +$ +144,629 +Year Ended September 30, +2015 +2014 +2013 +United States +$ +21,918 +$ +18,864 +$ +17,527 +United Kingdom +5,782 +5,647 +5,590 +Germany +5,699 +7,232 +6,465 +Australia +3,590 +4,063 +3,454 +China +2,107 +776 +557 +France +2,026 +1,633 +1,440 +Other countries +7,594 +9,117 +9,024 +Total Life Science +$ +48,716 +$ +47,332 +$ +44,057 +- 71 - +Table of Contents +Identifiable assets for our Italian distribution organization were $8,497 and $10,861 at September 30, 2015 +and 2014, respectively. At September 30, 2015, identifiable assets for the Bioline Group’s operations in the U.K., Germany and Australia totaled approximately $15,647, $6,909 and $3,891, respectively; and totaled $14,985, $7,713 and +$4,171, respectively, at September 30, 2014. +Segment information for the years ended September 30, 2015, 2014 and 2013 is as follows: +Diagnostics +Life Science +Elim (1) +Total +Fiscal Year 2015 - +Net revenues - +Third-party +$ +146,114 +$ +48,716 +$ +— +$ +194,830 +Inter-segment +334 +1,300 +(1,634 +) +— +Operating income +43,305 +12,888 +(133 +) +56,060 +Depreciation and amortization +4,099 +2,510 +— +6,609 +Capital expenditures +3,112 +1,501 +— +4,613 +Goodwill +1,250 +21,099 +— +22,349 +Other intangible assets +2,364 +3,567 +— +5,931 +Total assets +119,939 +63,670 +(327 +) +183,282 +Fiscal Year 2014 - +Net revenues – +Third-party +$ +141,500 +$ +47,332 +$ +— +$ +188,832 +Inter-segment +432 +1,009 +(1,441 +) +— +Operating income +41,629 +10,861 +(98 +) +52,392 +Depreciation and amortization +4,283 +2,981 +— +7,264 +Capital expenditures +4,176 +1,130 +— +5,306 +Goodwill +1,250 +21,943 +— +23,193 +Other intangible assets +2,756 +5,057 +— +7,813 +Total assets +109,350 +67,834 +(255 +) +176,929 +Fiscal Year 2013 - +Net revenues – +Third-party +$ +144,629 +$ +44,057 +$ +— +$ +188,686 +Inter-segment +533 +1,223 +(1,756 +) +— +Operating income +46,735 +10,627 +(48 +) +57,314 +Depreciation and amortization +4,328 +2,824 +— +7,152 +Capital expenditures +2,031 +1,203 +— +3,234 +Goodwill +1,250 +21,865 +— +23,115 +Other intangible assets +1,561 +6,496 +— +8,057 +Total assets +111,719 +65,393 +(364 +) +176,748 +(1) +Eliminations consist of intersegment transactions. +- 72 - +Table of Contents +A reconciliation of segment operating expenses to consolidated earnings before income taxes for the years ended +September 30, 2015, 2014 and 2013 is as follows: +Year Ended September 30, +2015 +2014 +2013 +Segment operating income +$ +56,060 +$ +52,392 +$ +57,314 +Interest income +23 +25 +44 +Other, net +(1,020 +) +(309 +) +4 +Consolidated earnings before income taxes +$ +55,063 +$ +52,108 +$ +57,362 +Transactions between segments are accounted for at established intercompany prices for internal and management purposes with +all intercompany amounts eliminated in consolidation. +(8) +Commitments and Contingencies +(a) +Royalty Commitments - We have entered into various license agreements that require payment of royalties based on a specified percentage of the sales of licensed products (1% to 14%). These royalty expenses are +recognized on an as-earned basis and recorded in the year earned as a component of cost of sales. Annual royalty expenses associated with these agreements were approximately $3,106, $3,482 and $3,611, respectively, for the fiscal years ended +September 30, 2015, 2014 and 2013. +(b) +Purchase Commitments - Excluding the operating lease commitments reflected in Note 8(c) below, we have purchase commitments primarily for inventory and service items as part of the normal course of business. +Commitments made under these obligations are $8,226 and $237 for fiscal 2016 and 2017, respectively. No purchase commitments have been made beyond fiscal 2017. +(c) +Operating Lease Commitments - Meridian and its subsidiaries are lessees of (i) certain office and warehouse buildings in the U.S., Europe, Australia, Singapore and China; (ii) automobiles for use by the +direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile and copier machines across all business units, under operating lease agreements that expire at various dates. Amounts charged to expense under +operating leases were $1,797, $1,951 and $1,744 for fiscal 2015, 2014 and 2013, respectively. Operating lease commitments for each of the five succeeding fiscal years are as follows: fiscal 2016 - $1,632, fiscal 2017 - $1,395, fiscal 2018 - $787, +fiscal 2019 - $240, and fiscal 2020 - $89. +(d) +Litigation - We are a party to various litigation matters from time to time that we believe are in the normal course of business. The ultimate resolution of these matters is not expected to have a material +adverse effect on our financial position, results of operations or cash flows. +- 73 - +Table of Contents +(e) +Indemnifications - In conjunction with certain contracts and agreements, we provide routine indemnifications whose terms range in duration and in some circumstances are not explicitly defined. The maximum +obligation under some such indemnifications is not explicitly stated and, as a result of our having no history of paying such indemnifications, cannot be reasonably estimated. We have not made any payments for these indemnifications and no liability +is recorded at September 30, 2015 or September 30, 2014. We believe that if we were to incur a loss on any of these matters, the loss would not have a material effect on our financial condition. +(9) +Quarterly Financial Data (Unaudited) +The sum of the earnings per common share may not equal the corresponding annual amounts due to interim quarter rounding. +For the Quarter Ended in Fiscal 2015 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +48,013 +$ +51,545 +$ +48,204 +$ +47,068 +Gross profit +29,237 +32,521 +30,331 +29,793 +Net earnings +7,901 +10,070 +9,102 +8,467 +Basic earnings per common share +0.19 +0.24 +0.22 +0.20 +Diluted earnings per common share +0.19 +0.24 +0.22 +0.20 +Cash dividends per common share +0.20 +0.20 +0.20 +0.20 +For the Quarter Ended in Fiscal 2014 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +44,794 +$ +50,134 +$ +47,212 +$ +46,692 +Gross profit +28,007 +31,593 +29,242 +28,401 +Net earnings +7,426 +10,300 +8,835 +8,182 +Basic earnings per common share +0.18 +0.25 +0.21 +0.20 +Diluted earnings per common share +0.18 +0.24 +0.21 +0.20 +Cash dividends per common share +0.19 +0.20 +0.20 +0.20 +(10) +Subsequent Events +We evaluated subsequent events after the balance sheet date of September 30, 2015 and there were no material subsequent events that +required recognition or additional disclosure in these financial statements. +During November 2015, we made a minority investment in Oasis Diagnostics ® Corporation in order to evaluate our interest in saliva diagnostics and collection devices. Oasis is located in Vancouver, Washington. +- 74 - +Table of Contents +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE +Not applicable. +ITEM 9A. +CONTROLS AND PROCEDURES +As of +September 30, 2015, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended. Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure +controls and procedures were effective as of September 30, 2015. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal +quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2015. +Our internal control report is included in this Annual Report on Form 10-K after Item 8, under the caption “Management’s Report on Internal +Control over Financial Reporting.” +ITEM 9B. +OTHER INFORMATION +Not applicable. +- 75 - +Table of Contents +PART III. +The information required by Items 10, 11, 12 (other than that portion set forth below), 13 and 14, of Part III are incorporated by reference from the +Registrant’s Proxy Statement for its 2016 Annual Shareholders’ Meeting to be filed with the Commission pursuant to Regulation 14A. +ITEM 12. +EQUITY COMPENSATION PLAN INFORMATION +The +following table presents summary information as of September 30, 2015 with respect to all of our equity compensation plans (number of securities information in thousands). +Plan Category +(a) +Number of +Securities to be +issued upon +exercise of +outstanding +options, warrants +and rights +(b) +Weighted- +average exercise +price of +outstanding +options, +warrants and +rights +(c) +Number of securities +remaining available +for future issuance +under equity +compensation plans +(excluding +securities +reflected in column +(a)) +Equity compensation plans approved by security holders (1) +816 +$ +20.543 +3,594 +Total (2) +816 +$ +20.543 +3,594 +(1) +2004 Equity Compensation Plan, as amended +2012 Stock Incentive Plan +(2) +Weighted-average remaining term of 4.86 years +- 76 - +Table of Contents +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) +(1) and (2) FINANCIAL STATEMENTS AND SCHEDULES. +All financial statements and schedules required to be +filed by Item 8 of this Form and included in this report have been so identified under Item 8. No additional financial statements or schedules are being filed since the requirements of paragraph (c) under Item 15 are not +applicable to Meridian. +(b) +(3) EXHIBITS. +Exhibit Number +Description of Exhibit +3.1 +Articles of Incorporation, including amendments not related to Company name change (Incorporated by reference to Registration Statement No. 333-02613 on Form S-3 filed with the Securities and Exchange Commission on April 18, 1996 +and Meridian’s Form 8-K filed with the Securities and Exchange Commission on May 16, 2007) +3.2 +Amended Code of Regulations (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on November 13, 2012) +10.1* +Savings and Investment Plan Prototype Adoption Agreement (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2003) +10.2* +Amendment No. 1 to Supplemental Benefit Agreement Dated September 23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on September +25, 2014) +10.3* +Supplemental Benefit Agreement between Meridian and John A. Kraeutler, as amended April 24, 2001, December 29, 2008, August 3, 2011 and June 12, 2012 (referred to as the Salary Continuation Agreement prior to June 12, 2012) +(Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on June 14, 2012) +10.4 +Dividend Reinvestment Plan (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 1999) +10.5* +Second Amended and Restated Employment Agreement Dated January 15, 2015 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on January 20, +2015) +10.6* +2004 Equity Compensation Plan, amended and restated effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.7* +2012 Stock Incentive Plan, effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.8* +Fiscal 2016 Officer’s Performance Compensation Plan (Filed herewith) +- 77 - +Table of Contents +Exhibit Number +Description of Exhibit +10.9 +Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc. Meridian Life Science, Inc. and Fifth Third Bank dated August 1, 2007 (Incorporated by reference to +Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2007) +10.10.1 +Amended and Restated Revolving Note with Fifth Third Bank dated April 21, 2015 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, 2015) +10.10.2 +First Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated September 2, 2010 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.10.3 +Second Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated December 1, 2010 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.10.4 +Third Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated September 15, 2012 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2012) +10.10.5 +Fifth Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank dated April 21, 2015 +(Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, 2015) +10.11* +Form of Time-Based Restricted Share Unit Award Agreement dated November 4, 2015 (Filed herewith) +10.12* +Form of Performance Award Restricted Share Unit Award Agreement dated November 4, 2015 (Filed herewith) +10.13* +Meridian Bioscience, Inc. Change in Control Severance Compensation Policy dated March 18, 2011 (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on March 24, 2011) +13 +2015 Annual Report to Shareholders (1) +14 +Code of Ethics (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2003) +21 +Subsidiaries of the Registrant (Filed herewith) +23 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +31.1 +Certification of Principal Executive Officer required by Rule 13a-14(a) (Filed herewith) +31.2 +Certification of Principal Financial Officer required by Rule 13a-14(a) (Filed herewith) +32 +Section 1350 Certification of Chief Executive Officer and Chief Financial Officer (Filed herewith) +101 +The following financial information from Meridian Bioscience Inc.’s Annual Report on Form 10-K for the fiscal year ended September 30, 2015 filed with the SEC on November 30, 2015, formatted in XBRL includes: (i) +Consolidated Statements of Operations for the years ended September 30, 2015, 2014 and 2013; (ii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2015, 2014 and 2013; (iii) Consolidated Statements of Cash +Flows for the years ended September 30, 2015, 2014 and 2013; (iv) Consolidated Balance Sheets as of September 30, 2015 and 2014; (v) Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2015, 2014 and +2013; and (vi) the Notes to Consolidated Financial Statements +- 78 - +Table of Contents +* +Management Compensatory Contracts +(1) +Only specific portions of the 2015 Annual Report to Shareholders are incorporated by reference in this Form 10-K as filed herewith. A supplemental paper copy of the 2015 Annual Report to Shareholders has been furnished +to the Securities and Exchange Commission for informational purposes only. +Meridian will provide shareholders with any exhibit upon the +payment of a specified reasonable fee, which fee shall be limited to Meridian’s reasonable expenses in furnishing such exhibit. +- 79 - +Table of Contents +SIGNATURES +Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +MERIDIAN BIOSCIENCE, INC. +By: +/s/ John A. Kraeutler +Date: November 30, 2015 +John A. Kraeutler +Chairman of the Board and +Chief Executive Officer +We, the undersigned directors and officers of the Registrant, hereby severally constitute John A. Kraeutler and Melissa +A. Lueke, and each of them singly, our true and lawful attorneys with full power to them and each of them to sign for us, in our names in the capacities indicated below, any and all amendments to the Annual Report on Form 10-K filed with the +Securities and Exchange Commission. +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following +persons on behalf of the Registrant and in the capacities and on the dates indicated. +Signature +Capacity +Date +/s/ John A. Kraeutler +John A. Kraeutler +Chairman of the Board and Chief Executive Officer +November 30, 2015 +/s/ Melissa A. Lueke +Melissa A. Lueke +Executive Vice President, Chief Financial Officer, and Secretary (Principal Financial and Accounting Officer) +November 30, 2015 +/s/ James M. Anderson +James M. Anderson +Director +November 30, 2015 +/s/ Dwight E. Ellingwood +Dwight E. Ellingwood +Director +November 30, 2015 +/s/ John C. McIlwraith +John C. McIlwraith +Director +November 30, 2015 +/s/ David C. Phillips +David C. Phillips +Director +November 30, 2015 +/s/ Catherine A. Sazdanoff +Catherine A. Sazdanoff +Director +November 30, 2015 +- 80 - +Table of Contents +SCHEDULE II +Meridian Bioscience, Inc. +and +Subsidiaries +Valuation and Qualifying Accounts +(Dollars in thousands) +Years Ended +September 30, 2015, 2014 and 2013 +Description +Balance at +Beginning +of Period +Charged to +Costs and +Expenses +Deductions +Other (a) +Balance at +End of +Period +Year Ended September 30, 2015: +Allowance for doubtful accounts +$ +272 +$ +73 +$ +(41 +) +$ +(56 +) +$ +248 +Inventory realizability reserves +2,942 +208 +(590 +) +(104 +) +2,456 +Valuation allowances – deferred taxes +8 +7 +— +— +15 +Year Ended September 30, 2014: +Allowance for doubtful accounts +$ +233 +$ +116 +$ +(68 +) +$ +(9 +) +$ +272 +Inventory realizability reserves +2,499 +1,325 +(834 +) +(48 +) +2,942 +Valuation allowances – deferred taxes +296 +8 +(296 +) +— +8 +Year Ended September 30, 2013: +Allowance for doubtful accounts +$ +574 +$ +(116 +) +$ +(239 +) +$ +14 +$ +233 +Inventory realizability reserves +2,271 +1,132 +(938 +) +34 +2,499 +Valuation allowances – deferred taxes +450 +150 +(289 +) +(15 +) +296 +(a) +Balances reflect the effects of currency translation. +- 81 - \ No newline at end of file diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/filing_metadata.csv b/raw/filings/0000794172/2015/0001193125-15-390041/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..4d96f5960d69bac6b6dfb53903060c9e28f44fb1 --- /dev/null +++ b/raw/filings/0000794172/2015/0001193125-15-390041/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000794172,VIVO,MERIDIAN BIOSCIENCE INC,10-K,2015-11-30,2015-09-30,2015-11-30T14:04:07.000Z,0001193125-15-390041,d74026d10k.htm,ANNUAL REPORT,5028082,1,0,https://www.sec.gov/Archives/edgar/data/794172/000119312515390041/d74026d10k.htm,https://www.sec.gov/Archives/edgar/data/794172/000119312515390041/,2015,2015,1 diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/item1.txt b/raw/filings/0000794172/2015/0001193125-15-390041/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..f820c07d7d76b084a7af05bc81d8493779c6e43b --- /dev/null +++ b/raw/filings/0000794172/2015/0001193125-15-390041/item1.txt @@ -0,0 +1,333 @@ +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in (i) the development, manufacture, sale and distribution of diagnostic +test kits, primarily for certain gastrointestinal, viral, respiratory and parasitic infectious diseases; (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch +reagents used by researchers and other diagnostic manufacturers; and (iii) the contract development and manufacture of proteins and other biologicals under cGMP conditions for use by biopharmaceutical and biotechnology companies engaged in +research for new drugs and vaccines. The Company was incorporated in Ohio in 1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form +8-K and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the Securities and Exchange Commission (SEC). These reports may also be +read and copied at the SEC’s public reference room at 100 F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these filings and other information regarding Meridian at +www.sec.gov . The information on our website is not and should not be considered part of this Annual Report on Form 10-K. +- 5 - +Table of Contents +Reportable Segments +Our reportable segments are Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. The Diagnostics segment consists of +manufacturing operations in Cincinnati, Ohio, and the sale and distribution of diagnostic test kits in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other +countries outside of the Americas and EMEA (rest of the world, or “ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, +Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents domestically and abroad, including sales and business development offices in Singapore and Beijing, China +to further pursue growing revenue opportunities in Asia. The Life Science segment also includes the contract development and manufacture of cGMP clinical grade proteins and other biologicals for use by biopharmaceutical and biotechnology companies +engaged in research for new drugs and vaccines. Financial information for Meridian’s reportable segments is included in Note 7 to the consolidated financial statements. +Diagnostics Segment +Overview of Products and +Markets +Our primary source of revenues continues to be diagnostic products, with our Diagnostics segment providing 75% of consolidated net +revenues for fiscal 2015. Third-party revenues for this segment were $146,000, $142,000 and $145,000 for fiscal 2015, 2014 and 2013, respectively, reflecting a three-year compound annual growth rate of 4%. As of September 30, 2015, our +Diagnostics segment had approximately 360 employees in seven countries. +Our diagnostic products provide accuracy, simplicity and speed; enable early +diagnosis and treatment of common, acute medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that (i) are acute conditions where rapid diagnosis impacts patient outcomes; +(ii) have opportunistic demographic and disease profiles; (iii) are underserved by current diagnostic products; and (iv) have difficult sample handling requirements (stool, blood, urine and other body fluids). This approach has +allowed us to establish significant market share in our target disease states. +Our diagnostic products span a broad menu of testing platforms and +technologies, and also include transport media that store and preserve specimen samples from patient collection to laboratory testing. Our testing platforms include: +• +Isothermal DNA Amplification ( illumi gene ® brand ) – high sensitivity, molecular platform that is suitable for +virtually any size laboratory, whether centralized or decentralized; provides flexibility to process from 1 to 10 tests per run in generally under one hour; and requires no batching of samples. +• +Rapid Immunoassay ( TRU ® , Immuno Card ® and +Immuno Card STAT! ® brands) – single-use immunoassays that can be used in point-of-care settings; these tests have fast turnaround times +(generally under 20 minutes); and can reduce expensive send-outs for hospitals and outpatient clinics. +- 6 - +Table of Contents +• +Enzyme-linked Immunoassay (Premier ® brand) – batch immunoassay platform that can process up to 96 tests per run; is highly +accurate and economical; and is adaptable to automation. +Our diagnostic products are used principally in the detection of infectious +diseases caused by various bacteria, viruses, parasites and pathogens. Our focus product families in Diagnostics are: +1. +C. difficile – causative agent for antibiotic-associated diarrhea from a hospital-acquired infection +2. +Foodborne – Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy) +3. +H. pylori – stomach ulcers +4. +Respiratory – Group A Streptococcus , M. pneumonia (Mycoplasma) and Bordetella pertussis , among tests for other diseases +5. +Women’s Health & Sexually Transmitted Diseases (“STD”) – Group B Streptococcus , Chlamydia trachomatis , Neisseria gonorrhea , Herpes Simplex Virus Type 1 & Type +2 +Revenues within these focus product families accounted for 79%, 77% and 77% of our Diagnostics segment’s third-party revenues during +fiscal 2015, 2014 and 2013, respectively. These same product families accounted for 59%, 58% and 59% of consolidated net revenues in fiscal 2015, 2014 and 2013, respectively. +Our product portfolio includes over 140 diagnostic tests and transport media, and is marketed to acute care hospitals, reference laboratories and outpatient +clinics in over 70 countries around the world. +We continue to invest in new product development for our molecular testing platform, +illumi gene . This platform now has the following commercialized tests (assays): +1. +illumi gene ® C. difficile – commercialized in August 2010 +2. +illumi gene ® Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene ® Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene ® Mycoplasma ( M. pneumonia; walking pneumonia) – commercialized in June 2013 +5. +illumi gene ® Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene ® Chlamydia trachomatis – commercialized outside of U.S. in February 2015 +7. +illumi gene ® Neisseria gonorrhea – commercialized outside of U.S. in February 2015 +8. +illumi gene ® HSV 1&2 (Herpes Simplex Virus Type 1 & Type 2) – commercialized outside of U.S. in May 2015; commercialized in U.S. +in July 2015 +We have several additional illumi gene tests in development, including +bloodborne pathogens that are the causative agents for malaria. We have a robust pipeline of illumi gene opportunities and continue to add new assays to our illumi gene platform +menu. +- 7 - +Table of Contents +We believe that our illumi gene system has been well-accepted in +our global markets. We now have approximately 1,465 customer account placements. Of these account placements, approximately 1,300 accounts have completed evaluations and validations and are regularly purchasing product, with the balance of our +account placements being in some stage of product evaluation and/or validation. Of our account placements, we have over 400 accounts that are regularly purchasing, evaluating and/or validating two or more assays. +Market Trends +The global market for infectious +disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. More importantly, within this market, there is a continuing shift from +conventional testing, which requires highly trained personnel and lengthy turnaround times for test results, to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The increasing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. With rapid and accurate +diagnoses of infectious diseases, physicians can pinpoint appropriate therapies quickly, leading to faster recovery, shorter hospital stays and lower overall treatment cost. The creation of Accountable Care Organizations (ACOs) in our U.S. market, +in particular, has the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with ACOs and health care systems that are transitioning +from fee-for-service compensation models, to compensation models based on the total outcome costs of a given patient. Our C. difficile , Group B Streptococcus , Group A Streptococcus , and H. pylori products are all examples +of how a highly accurate diagnostic test on the front end can mitigate or reduce down-stream costs for antibiotic use, symptom-relieving drugs and hospital stays. +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing organizations and integrated delivery networks, +consolidation among reference laboratories, and acquisition of physician practices by hospitals. We utilize multi-year supply agreements to secure our business where possible and appropriate. +Cost containment pressures have also affected health care systems outside the U.S., particularly in Europe, where the health care systems are generally +government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing +and Focus Product Families +Our Diagnostics segment’s sales and distribution network consists of the following for each of the broad +geographic regions we serve: +- 8 - +Table of Contents +North America +In North America, our sales and distribution network consists of a direct sales force (U.S. only) complemented by independent distributors. The +use of independent distributors in the U.S. allows our products to reach any size health care facility and also provides our customers the option to purchase our products directly from Meridian or through an authorized distributor. Two independent +distributors in the U.S. accounted for 10% or more of consolidated net revenues in fiscal 2015, 2014 and 2013: Cardinal Healthcare Corporation and Thermo Fisher Scientific. Our revenues from Cardinal were approximately $29,000, $28,000 and $35,000 +during fiscal 2015, 2014 and 2013, respectively. Our revenues from Thermo Fisher were approximately $25,000, $23,000 and $25,000 during fiscal 2015, 2014 and 2013, respectively. +EMEA +In EMEA, our sales +and distribution network consists of direct sales forces in Belgium, France, Holland and Italy, and independent distributors in other European countries, Africa and the Middle East. We have implemented a direct sales presence in Germany and the U.K. +for our illumi gene products, and utilize independent distributors for our immunoassay products. We maintain a distribution center near Milan, Italy. +ROW +With the exception +of Australia, in which we utilize a direct sales force, we utilize independent distributors throughout the ROW. +Our Diagnostics segment’s focus +product families are described below: +C. difficile +C. difficile , causative agent of serious hospital acquired bacterial infections, is our largest product family, generating approximately $31,000 in +global revenues for fiscal 2015, a 12% decrease from fiscal 2014 – reflecting a combination of sales of our molecular-based and traditional immunoassay products, with our molecular product now representing approximately 80% of this product +category. This product family has experienced significant competition in recent years from new technologies, primarily other molecular testing platforms. See Competition discussion below. +Foodborne +Our foodborne product family achieved +approximately $25,000 in global revenues for fiscal 2015, an increase of 8%, with over 95% of such sales occurring in the U.S. Our foodborne products include tests for Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy). +In the U.S. market, we believe that there are potentially 20 million stool cultures that are tested annually for foodborne illnesses. We believe that we have less than a 20% market share for EHEC and less than a 5% market share for Campy. +- 9 - +Table of Contents +We are continuing to re-emphasize the benefits of increased sensitivity and faster turnaround time versus culture +methods in our marketing programs. The primary competition for our foodborne products is laboratory culture methods and an immunoassay EHEC shiga toxin test from one of our competitors. We believe that our test offers better workflow, less hands-on +time and quicker results, in addition to being fully compliant with CDC-recommended testing methods. +Helicobacter pylori +H. pylori , a bacterium found in the stomach, is a major cause of peptic ulcers and is linked to duodenal ulcers and stomach cancer. H. pylori +represents our second largest product family, generating approximately $30,000 in global revenues for 2015, or 6% growth. We offer both antibody and direct antigen tests in alternative formats (single-use and high volume batch). Our major +competition in this product family is alternative test methods, serology and urea breath, and the prescription of symptom-relieving medications. Over 75% of our H. pylori product sales are in the U.S., where our strategy for this product line +has been to partner with managed care companies to promote the health and economic benefits of a test and treat strategy, and to move physician behavior away from serology-based testing toward direct antigen testing. In the U.S. market, we believe +that there are potentially 30 million people suffering from peptic ulcers and we believe that we currently have an approximate 5% market share. +The patents for our H. pylori products are owned by us and expire in May 2016 in the U.S. and in 2017 in countries outside the U.S. We expect +competition with respect to our H. pylori products to increase upon the expiration of these patents in 2016 and 2017 as we currently market the only FDA-cleared test to detect H. pylori antigen in stool samples. Such competition may +have an adverse impact on our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In +order to mitigate any loss in revenues upon patent expiration, among other things, we are researching and experimenting with new products (e.g., detection of H. pylori on molecular platforms) and attempting to secure significant customers +under long-term contracts. We are unable to provide any assurances that we will be successful with any mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including +revenues and gross profit. +Respiratory +In addition to our immunoassay tests to detect influenza, which have been part of our product portfolio for a number of years, during the last +three years we have also introduced three molecular-based products on our illumi gene platform to detect various respiratory conditions. These molecular products, which are less seasonally-dependent than our +influenza products, include illumi gene Group A Strep (2012), illumi gene Mycoplasma (2013) and illumi gene Pertussis (2014). Since their +commercialization, these products have been widely accepted in the marketplace and during fiscal 2015 grew to represent over 40% of our total Respiratory product family revenues of $22,000. +- 10 - +Table of Contents +Women’s Health & STD +In December 2011, we introduced our illumi gene Group B Strep product to detect Group B Streptococcus (GBS) in +expectant mothers. Early detection of GBS, a major perinatal pathogen for both mothers and their infants that is associated with significant morbidity and mortality, is critical to the prevention and treatment of serious disease in infants. During +fiscal 2015, we expanded our illumi gene molecular product platform to include three additional tests directly related to women’s health; these include tests for Chlamydia trachomatis (Chlamydia), Neisseria +gonorrhea (Gonorrhea) and Herpes Simplex Virus Type 1 & Type 2. With the GBS and HSV tests available worldwide, and the Chlamydia and Gonorrhea tests currently commercialized only outside the U.S., revenues from these women’s +health & STD products grew to over $7,000 during 2015, and are currently expected to exceed $10,000 in fiscal 2016. +Competition +Our major competitors in molecular diagnostics are Cepheid and Becton Dickinson, who have systems with multiple-assay menus. We also face +competition in molecular diagnostics, but to a lesser degree, from companies such as Alere, Great Basin, Nanosphere and Quidel. These latter companies have a limited commercial menu and tend to compete strictly on price. We believe that our +molecular platform offers a number of competitive features: +• +Molecular assay sensitivity that is comparable to higher costing PCR; +• +Low capital investment with no instrument service cost; +• +Small footprint that is portable and does not consume much laboratory space; and +• +Product menu that fits with initiatives to improve clinical and economic outcomes. +Our major competitors in +rapid immunoassay diagnostics are primarily Alere and Quidel. These companies tend to compete strictly on price. We believe that with the breadth and depth of our product portfolio, we are well positioned to capitalize on the migration to molecular +testing. +Research and Development +Our +Diagnostics segment’s research and development organization, which is located at our corporate headquarters in Newtown, Ohio, a suburb of Cincinnati, has expertise in biochemistry, immunology, mycology, bacteriology, virology, parasitology and +molecular biology. Research and development expenses for the Diagnostics segment for fiscal 2015, 2014 and 2013 were approximately $10,000, $10,000 and $8,000, respectively. This research and development organization focuses its activities on new +product and new technology development, new applications for our existing technologies, and improvements to existing products. Research and development efforts may occur in-house or with collaborative partners. We believe that new product +development is a key source for sustaining revenue growth. The products within our illumi gene molecular platform and H. pylori product family were developed solely in-house. +- 11 - +Table of Contents +Manufacturing +Our immunoassay and molecular products require the production of highly specific and sensitive antigens, antibodies, primers and enzymes. While +we produce substantially all of our own requirements including monoclonal and polyclonal antibodies, and a variety of fungal, bacterial and viral antigens, currently a number of the raw materials used in our products, including our +illumi gene molecular products, are purchased from outside vendors. With the recent expansion of our molecular diagnostic manufacturing capacity at our Cincinnati, Ohio location, we brought in-house certain +molecular component manufacturing that was previously outsourced. We believe that we have sufficient manufacturing and sourcing capacity for anticipated growth over the next several years. +Intellectual Property, Patents and Licenses +We +own or license U.S. and foreign patents, most of which are for products manufactured by our Diagnostics segment. These patents are used in our manufacturing processes for selected products (method patents) or may relate to the design of the test +device technology format (design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully replicate our production and manufacturing technologies and processes. Our employees are required to sign +confidentiality and non-disclosure agreements designed to protect our proprietary products. Revenues from these products in fiscal 2015 and fiscal 2014 were as follows: +Product/Technology Family +Number of +products +% of fiscal year +consolidated revenues +2015 +2014 +illumi gene +8 +21 +% +20 +% +H. pylori +2 +14 +% +14 +% +Respiratory immunoassay +4 +2 +% +2 +% +Other +5 +1 +% +1 +% +Total patented products +19 +38 +% +37 +% +The patents for the illumi gene products are licensed from a third party under +a non-exclusive license agreement and expire between 2020 and 2022. These patents were issued in the U.S., European Community and other countries. The term of our license agreement runs until the last patent expires in 2022, at which point we will +be free to practice the patents without any restriction or royalty obligation. +The patents for our H. pylori products are +owned by us and expire in May 2016 in the U.S. and in 2017 outside the U.S. (principally, Australia, Canada, European Community and Japan). We expect competition with respect to our H. pylori products to increase upon the expiration of these +patents in 2016 and 2017 as we currently market the only FDA-cleared test to detect H. pylori antigen in stool samples. Such competition may have an adverse impact on our selling prices for these products or our ability to retain business at +prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to mitigate any loss in revenues upon patent expiration, we are researching and experimenting +with new products (e.g., detection of H. pylori in samples other than stool and detection of H. pylori on molecular platforms). We are unable to provide any assurances that we will be successful with any mitigation strategy or that any +mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and gross profit. +- 12 - +Table of Contents +The patents for our immunoassay respiratory products are owned by us and expire in 2022 (two products) and 2027 +(one product). These patents were issued in the U.S. and European Community, among other jurisdictions. +The remaining five patented products are spread +over multiple product families. These patents are either owned by us, or we are free to practice the patents without any restriction or royalty obligation. These patents, where still in effect, collectively expire between 2016 and 2027. +Government Regulation +Our diagnostic products are +regulated by the Food & Drug Administration (FDA) as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (FDCA). Under the FDCA, medical devices are classified into one of three classes (i.e., Class I, II or III). Class +I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally must receive “pre-market approval” from the FDA as to safety and effectiveness. +Each of the diagnostic products currently marketed by us in the United States has been cleared by the FDA pursuant to the 510(k) clearance process or is +exempt from such requirements. We believe that most, but not all, products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all Class II devices, will be eligible for 510(k) clearance; +however, we can make no assurances in this regard. Meridian’s TRU FLU ® rapid influenza assay was cleared in 2006 as a Class I device. In May 2014, the FDA proposed reclassifying +rapid influenza assays as a Class II device, requiring the submission of a new 510(k) application and subjecting TRU FLU and similar competitive devices to increased requirements for sensitivity. If the proposed rule becomes effective, Meridian +will have one year to bring its assay up to the new requirements or remove it from the market. Sales of the TRU FLU product totaled approximately $2,000 in fiscal 2015. +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, largely similar to that of the FDA. +Meridian’s Cincinnati manufacturing facility is certified to ISO 13485:2012. +- 13 - +Table of Contents +Medical Device Tax +On January 1, 2013, the medical device tax established as part of the U.S. health care reform legislation became effective and as a result, the Company +made its first required tax deposit near the end of January 2013. During fiscal 2015, 2014 and 2013, the Company recorded to cost of sales approximately $1,900, $1,750 and $1,300, respectively, of medical device tax expense related to this +legislation. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory and parasitic infectious +diseases. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses, or pandemics such as the H1N1 influenza outbreak during fiscal 2009. While we believe that the +breadth of our diagnostic product lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be impacted period over +period by such factors. +Life Science Segment +Overview of Products and Markets +Our Life Science +segment’s business focuses on the development, manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing +companies, as well as contract development and manufacturing services under clinical cGMP conditions. Third-party revenues for this segment were approximately $49,000, $47,000 and $44,000 for fiscal 2015, 2014 and 2013, respectively. As of +September 30, 2015, our Life Science segment had approximately 220 employees in seven countries. +Most of the revenues for our Life Science segment +currently come from the manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies focused on the +development of immunoassay and molecular tests. Approximately 65% of Life Science revenues are generated from the industrial market, defined as diagnostic manufacturers and the agriculture industry. This is an increasing focus of our Bioline +molecular component business, which historically focused on the academic/research market that comprises the remaining 35% of Life Science revenues. We utilize direct sales teams in key countries such as the U.S., the U.K., Germany, France, Australia +and Singapore. Opened in 2013, the Singapore sales and business development office is designed to increase our presence and our revenue opportunities in Asia for both molecular and immunoassay components. Additionally, in order to further pursue +revenue opportunities in Asia, and China in particular, during fiscal 2015 we opened a representative office in Beijing, China. We utilize a network of distributors in other major countries. During fiscal 2015, 16% of third-party revenues for this +segment were from two diagnostic manufacturing customers. +- 14 - +Table of Contents +Products such as antibodies, antigens and reagents are marketed primarily to diagnostic manufacturing customers +as a source of raw materials for their immunoassay products, or as an outsourced step in their manufacturing processes. For example, we supply a number of major diagnostic manufacturers with proteins used to detect hepatitis A and rubella. These +products are typically sold in bulk quantities, and may also be custom-designed for a particular manufacturer’s requirements. Sales efforts are focused on multi-year supply arrangements in order to provide stability in volumes and pricing. We +believe this benefits both us and our customers. +Molecular biology products such as PCR/qPCR reagents, nucleotides and competent cells are marketed to +academic/research and industrial customers. These products are used in measuring DNA and RNA in clinical and agricultural applications. These reagents improve the purity, yield and speed of PCR reactions. Products such as MyTaq™ and +SensiFAST™ are examples of this type of PCR/qPCR reagent. +Our clinical cGMP protein production facility in Memphis, Tennessee serves as an enabling +technology for process development and large-scale manufacturing for biologicals used in new drugs and vaccines. The size of the facility is intended to accommodate manufacturing requirements for Phase I and Phase II clinical trials for +biopharmaceutical, biotechnology and government agency customers. Our revenues for contract services were approximately $3,000 in each of fiscal 2015, 2014 and 2013. +Market Trends +Globally, sales of molecular +components are growing at a faster pace than immunoassay components, and this is consistent with our business in constant-currency. Geographic expansion is a significant strategy for our Life Science segment, along with further penetration into +industrial markets with our molecular products. +Competition +The market for bulk biomedical reagents is highly competitive. Important competitive factors include product quality, price, customer service, and reputation. +We face competitors, many of which have greater financial, research and development, sales and marketing, and manufacturing resources, and where sole-source supply arrangements do not exist. Customers also may choose to manufacture their biomedical +reagents in-house rather than purchase from outside vendors such as Meridian. +The academic/research market is highly fragmented. Individual purchases are +typically of small quantities. The breadth of product offerings, quality, price and service, including on-line capabilities and technical resources, are important factors to building customer loyalty and repeat purchases. +The market for contract manufacturing in a validated cGMP facility, such as our Memphis facility, is also competitive. Important competitive factors include +reputation, customer service and price. Although the product application for this facility was built from our existing expertise in cell culture manufacturing techniques, we face competitors with greater experience in contract manufacturing in a +clinical cGMP environment. +- 15 - +Table of Contents +Research and Development +Research and development expenses for our Life Science segment for each of fiscal 2015, 2014 and 2013 were approximately $3,000. This research and development +organization is involved in activities for our cGMP facility and development of new molecular reagent products. +Manufacturing and Government +Regulation +Our Life Science facilities are ISO 9001:2008 certified, and where appropriate, comply with Regulation EC 1069:2009. +The cGMP clinical grade proteins that are produced in our Memphis facility are intended to be used as “injectibles,” and, as such, they are produced +under cGMP Regulations for Biologics and Human Drugs under the auspices of the FDA. Following clinical trials, approval and licensing of these products is the responsibility of the applicant, who owns the rights to each protein. Typically, the +customer is the applicant, not Meridian Life Science. +Acquisitions +Acquisitions have played an important role in the growth of our businesses. Our acquisition objectives include, among other things: (i) enhancing product +offerings; (ii) improving product distribution capabilities; (iii) providing access to new markets; and/or (iv) providing access to key biologicals or new technologies that lead to new products. Although we cannot provide any +assurance that we will consummate any additional acquisitions in the future, nor can we provide any assurance that any acquisitions will accomplish these objectives, we expect that the potential for acquisitions will continue to provide +opportunities for revenue and earnings growth in the future. +During November 2015, we made a minority investment in Oasis Diagnostics ® Corporation in order to evaluate our interest in saliva diagnostics and collection devices. Oasis is located in Vancouver, Washington. +International Markets +International markets are an +important source of revenues and future growth opportunities for both of our segments. For both segments combined, revenues from customers located outside of North America approximated $49,000 or 25% of consolidated fiscal 2015 revenues, $55,000 or +29% of consolidated fiscal 2014 revenues, and $54,000 or 29% of consolidated fiscal 2013 revenues. We expect to continue to look to international markets as a source of new revenues and growth in the future. +- 16 - +Table of Contents +During fiscal 2015, currency exchange had an approximate $4,700 unfavorable impact on revenues; $3,200 within the +Diagnostics segment and $1,500 within the Life Science segment. This compares to currency exchange rates having an approximate $850 favorable impact on revenues in fiscal 2014; $600 favorable within the Diagnostics segment and $250 within the Life +Science segment. Due to natural hedge relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net earnings was not material during fiscal 2015, 2014 or 2013. +Environmental +We are a conditionally exempt, small +quantity generator of hazardous waste and have a U.S. EPA identification number. We are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. \ No newline at end of file diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/item13.txt b/raw/filings/0000794172/2015/0001193125-15-390041/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..305758b6c3f2fd9d744dacfc77d2da00788b0e6c --- /dev/null +++ b/raw/filings/0000794172/2015/0001193125-15-390041/item13.txt @@ -0,0 +1,3 @@ +Item 13 +Certain Relationships and Related Transactions, and Director Independence +76 \ No newline at end of file diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/item9a.txt b/raw/filings/0000794172/2015/0001193125-15-390041/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..8906d1c44ae312cd471a87550d2bf03ef45fed14 --- /dev/null +++ b/raw/filings/0000794172/2015/0001193125-15-390041/item9a.txt @@ -0,0 +1,9 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +As of +September 30, 2015, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended. Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure +controls and procedures were effective as of September 30, 2015. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal +quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2015. +Our internal control report is included in this Annual Report on Form 10-K after Item 8, under the caption “Management’s Report on Internal +Control over Financial Reporting.” \ No newline at end of file diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/rp_note.txt b/raw/filings/0000794172/2015/0001193125-15-390041/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000794172/2015/0001193125-15-390041/rpt_disclosure.txt b/raw/filings/0000794172/2015/0001193125-15-390041/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..f44d0988bfc20269b6dfd6fec0fab43dc4eee13f --- /dev/null +++ b/raw/filings/0000794172/2015/0001193125-15-390041/rpt_disclosure.txt @@ -0,0 +1,13 @@ +TRANSACTIONS WITH RELATED PERSONS +During fiscal 2016, the Company leased certain office space from an entity controlled by Marco G. Calzavara, President and Managing Director, Meridian +Bioscience Europe. Payments made under such arrangements during fiscal 2016 totaled approximately $170,000. +Nasdaq rules require the +Company to conduct an appropriate review of related party transactions required to be disclosed by the Company pursuant to SEC Regulation S-K Item 404 for potential conflict of interest situations on an ongoing basis and that all such transactions +must be approved by the Audit Committee or another Committee comprised of independent Directors. As a result, the Audit Committee annually reviews all such related party transactions and approves each related party transaction if it determines +that it is in the best interests of the Company. Additionally, the Audit Committee’s Charter provides it the authority to review, approve and monitor transactions involving the Company and “related persons” (Directors and +Executive Officers or their immediate family members, or shareholders owning five percent or greater of the Company’s outstanding stock). This also covers any related person transaction that meets the minimum threshold for disclosure in +the proxy statement under the relevant SEC rules (generally, transactions involving amounts exceeding $120,000 in which a related person has a direct or indirect material interest). In considering the transaction, the Audit Committee may +consider all relevant factors, including, as applicable: (i) the Company’s business rationale for entering into the transaction; (ii) the alternatives to entering into a related person transaction; (iii) whether the transaction is on terms +comparable to those available to third parties, or in the case of employment relationships, to employees generally; (iv) the potential for the transaction to lead to an actual or apparent conflict of interest and any safeguards imposed to prevent +such actual or apparent conflicts; and (v) the overall fairness of the transaction to the Company. This policy is included in the Company’s Employee Handbook. The approval of such related person transactions are evidenced by internal +Company resolutions or memoranda. \ No newline at end of file diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/filing.txt b/raw/filings/0000794172/2016/0001193125-16-779250/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..ce9b840ef2ab77ee5b69350e4f1c9d68f1e8ecc2 --- /dev/null +++ b/raw/filings/0000794172/2016/0001193125-16-779250/filing.txt @@ -0,0 +1,3950 @@ +10-K +1 +d270799d10k.htm +ANNUAL REPORT +Annual Report +Table of Contents +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +FOR ANNUAL +AND TRANSITION REPORTS +PURSUANT TO SECTIONS 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2016. +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM +TO +Commission File No. 0-14902 +MERIDIAN +BIOSCIENCE, INC. +3471 River Hills Drive +Cincinnati, Ohio 45244 +IRS Employer ID No. 31-0888197 +Incorporated under the Laws of Ohio +Phone: (513) 271-3700 +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange of which +registered +Common Shares, No Par Value +The NASDAQ Stock Market LLC +(NASDAQ Global Select Market) +Securities Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the +registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +YES ☒ NO ☐ +If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of +the Securities Exchange Act. +YES ☐ NO ☒ +Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 +during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. +YES ☒ NO ☐ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required +to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). +YES ☒ NO ☐ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this Chapter) is not contained +herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. +☒ +Indicate by check mark whether the registrant is a large accelerated filer, an +accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +☒ +Accelerated filer +☐ +Non-accelerated filer +☐ (Do not check if a smaller reporting company) +Smaller reporting company +☐ +Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). +YES ☐ NO ☒ +The aggregate market value of Common Shares held by non-affiliates as of March 31, 2016 was $856,265,348 based on a closing sale price of $20.61 per share on +March 31, 2016. As of October 31, 2016, 42,108,217 no par value Common Shares were issued and outstanding. +Documents Incorporated +by Reference +Portions of the Registrant’s Annual Report to Shareholders for the fiscal year ended September 30, 2016 furnished to the Commission +pursuant to Rule 14a-3(b) are incorporated by reference in Part II as specified and portions of the Registrant’s Proxy Statement to be filed with the Commission for its 2017 Annual Shareholders’ +Meeting are incorporated by reference in Part III as specified. +Table of Contents +MERIDIAN BIOSCIENCE, INC. +INDEX TO ANNUAL REPORT +ON FORM 10-K +Page +Part I +Item 1 +Business +5 +Item 1A +Risk Factors +15 +Item 1B +Unresolved Staff Comments +24 +Item 2 +Properties +24 +Item 3 +Legal Proceedings +25 +Item 4 +Mine Safety Disclosures +25 +Part II +Item 5 +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +26 +Item 6 +Selected Financial Data +26 +Item 7 +Management’s Discussion and Analysis of Financial Condition and Results of Operations +27 +Item 7A +Quantitative and Qualitative Disclosures about Market Risk +44 +Item 8 +Financial Statements and Supplementary Data +45 +Item 9 +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +78 +Item 9A +Controls and Procedures +78 +Item 9B +Other Information +78 +Part III +Item 10 +Directors, Executive Officers and Corporate Governance +78 +Item 11 +Executive Compensation +78 +Item 12 +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +78 +Item 13 +Certain Relationships and Related Transactions, and Director Independence +78 +Item 14 +Principal Accounting Fees and Services +78 +Item 15 +Exhibits and Financial Statement Schedules +79 +FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements. The Private Securities Litigation Reform Act of 1995 provides a safe harbor from +civil litigation for forward-looking statements accompanied by meaningful cautionary statements. Except for historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, +as amended, and Section 21E of the Securities Exchange Act of 1934, which may be identified by words such as “estimates”, “anticipates”, “projects”, “plans”, “seeks”, “may”, +“will”, “expects”, “intends”, “believes”, “should” and similar expressions or the negative versions thereof and which also may be identified by their context. All statements that address +operating performance or events or developments that Meridian expects or anticipates will occur in the future, including, but not limited to, statements relating to per share diluted earnings and revenue, are forward-looking statements. Such +statements, whether expressed or implied, are based upon current expectations of the Company and speak only as of the date made. Specifically, Meridian’s forward-looking statements are, and will be, based on management’s then-current +views and assumptions regarding future events and operating performance. Meridian assumes no obligation to publicly update or revise any forward-looking statements even if experience or future changes make it clear that any projected results +expressed or implied therein will not be realized. These statements are subject to various risks, uncertainties and other factors that could cause actual results to differ materially, including, without limitation, the following: +Meridian’s continued growth depends, in part, on its ability to introduce into the marketplace enhancements of existing products or new products that incorporate technological advances, meet customer requirements and respond to products +developed by Meridian’s competition, and its ability to effectively sell such products. While Meridian has introduced a number of internally developed products, there can be no assurance that it will be successful in the future in +introducing such products on a timely basis or in protecting its intellectual property. Meridian relies on proprietary, patented and licensed technologies. As such, the Company’s ability to protect its intellectual property rights, as +well as the potential for intellectual property litigation, would impact its results. Ongoing consolidations of reference laboratories and formation of multi-hospital alliances may cause adverse changes to pricing and +distribution. Recessionary pressures on the economy and the markets in which our customers operate, as well as adverse trends in buying patterns from customers, can change expected results. Costs and difficulties in complying with laws and +regulations, including those administered by the +Table of Contents +United States Food and Drug Administration, can result in unanticipated expenses and delays and interruptions to the sale of new and existing products, as well as the uncertainty of regulatory +approvals and the regulatory process. The international scope of Meridian’s operations, including changes in the relative strength or weakness of the U.S. dollar and general economic conditions in foreign countries, can impact results and +make them difficult to predict. One of Meridian’s growth strategies is the acquisition of companies and product lines. There can be no assurance that additional acquisitions will be consummated or that, if consummated, will be +successful and the acquired businesses will be successfully integrated into Meridian’s operations. There may be risks that acquisitions may disrupt operations and may pose potential difficulties in employee retention, and there may be +additional risks with respect to Meridian’s ability to recognize the benefits of acquisitions, including potential synergies and cost savings or the failure of acquisitions to achieve their plans and objectives. Meridian cannot predict the +possible impact of U.S. health care legislation enacted in 2010 – the Patient Protection and Affordable Care Act, as amended by the Health Care and Education Reconciliation Act – and any modification or repeal of any of the provisions +thereof, and any similar initiatives in other countries on its results of operations. Efforts to reduce the U.S. federal deficit, breaches of Meridian’s information technology systems and natural disasters and other events could have a +materially adverse effect on Meridian’s results of operations and revenues. In addition to the factors described in this paragraph, Part I, Item 1A Risk Factors of this Annual Report on Form 10-K contains a list and description of +uncertainties, risks and other matters that may affect the Company. Readers should carefully review these forward-looking statements and risk factors and not place undue reliance on our forward-looking statements. +Table of Contents +PART I. +This Annual Report on Form 10-K includes forward-looking statements about our business and results of operations that are subject to risks and +uncertainties. See “Forward-Looking Statements” above. Factors that could cause or contribute to such differences include those discussed in Item 1A. Risk Factors. In addition to the risk factors discussed herein, we are +also subject to additional risks and uncertainties not presently known to us or that we currently deem immaterial. If any of these risks and uncertainties develops into actual events, our business, financial condition or results of operations +could be adversely affected. +Unless the context requires otherwise, references in this Annual Report on Form 10-K to “Meridian,” +“we,” “us,” “our,” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +In the +discussion that follows, all dollars and shares are in thousands (both tables and text), except per share data. +This Annual Report on Form 10-K refers to +trademarks such as TRU FLU ® , Immuno Card ® , Immuno Card +STAT! ® , MyTaq ™ , SensiFAST ™ , PREMIER ® and LeadCare ® , which are protected under applicable intellectual property laws and are our property. Solely for convenience, our +trademarks and tradenames referred to in this Form 10-K may appear without the ® or ™ symbols, but such references are not intended to +indicate in any way that we will not assert, to the fullest extent under applicable law, our rights to these trademarks and tradenames. +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science +company with principal businesses in (i) the development, manufacture, sale and distribution of diagnostic test kits, primarily for certain gastrointestinal, viral, respiratory, and parasitic infectious diseases, and elevated blood lead levels; and +(ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch reagents used by researchers and other diagnostic manufacturers. The Company was incorporated in Ohio in +1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +During March 2016, we acquired all of the outstanding common stock of +Magellan Biosciences, Inc., and its wholly-owned subsidiary Magellan Diagnostics, Inc. (collectively, “Magellan”), which is now reported as part of our Diagnostics operating segment. Headquartered near Boston, Massachusetts, Magellan +is a leading manufacturer of FDA-cleared products for the testing of blood to diagnose lead poisoning in children and adults. Magellan is the leading provider of point-of-care lead testing systems in the U.S. +- 5 - +Table of Contents +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, +Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the Securities and +Exchange Commission (SEC). These reports may also be read and copied at the SEC’s public reference room at 100 F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these +filings and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered part of this Annual Report on Form 10-K. +Reportable Segments +Our reportable segments are +Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio, which also serves as the Diagnostics segment’s base of manufacturing operations and research and development for infectious disease products. The +Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, and the sale and distribution of diagnostic test kits in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and +Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, or “ROW”). As previously noted, the Diagnostics segment includes the Company’s recent acquisition of Magellan, which is located +in Billerica, Massachusetts (near Boston). Its facility includes research, development, manufacturing, marketing, sales, and distribution operations. The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca +Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch reagents domestically and abroad, including +sales and business development offices in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. Financial information for Meridian’s reportable segments is included in Note 8 to the consolidated financial +statements. +Diagnostics Segment +Overview of +Products and Markets +Our primary source of revenues continues to be diagnostic products, with our Diagnostics segment providing 74% of +consolidated net revenues for fiscal 2016. Third-party revenues for this segment were $145,000, $146,000 and $142,000 for fiscal 2016, 2015 and 2014, respectively. As of September 30, 2016, our Diagnostics segment had approximately 440 +employees in seven countries. +Our diagnostic products provide accuracy, simplicity and speed; enable early diagnosis and treatment of common, acute +medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that (i) are conditions where rapid diagnosis impacts patient outcomes; (ii) have opportunistic demographic and disease +profiles; (iii) are underserved by current diagnostic products; and (iv) have difficult sample handling requirements (stool, blood, urine and other body fluids). This approach has allowed us to establish significant market share in our target +disease states. +- 6 - +Table of Contents +Our diagnostic products span a broad menu of testing platforms and technologies, and also include transport media +that store and preserve specimen samples from patient collection to laboratory testing. Our testing platforms include: +• +Isothermal DNA Amplification ( illumi gene brand) – high sensitivity, molecular platform that is suitable for virtually any size laboratory, whether centralized or decentralized; +provides flexibility to process from 1 to 10 tests per run in generally under one hour; and requires no batching of samples. +• +Rapid Immunoassay (TRU, Immuno Card and Immuno Card STAT! brands) – single-use immunoassays that can be used in point-of-care settings; have fast turnaround +times (generally under 20 minutes); and can reduce expensive send-outs for hospitals and outpatient clinics. +• +Enzyme-linked Immunoassay (PREMIER brand) – batch immunoassay platform that can process up to 96 tests per run; is highly accurate and economical; and is adaptable to automation. +• +Anodic Stripping Voltammetry (LeadCare brand) – electrical chemical sensor platform for quantitative determination of lead levels in blood. +Our diagnostic products are used principally in the detection of infectious diseases caused by various bacteria, viruses, parasites and pathogens, including +most notably the following general areas: +• +C. difficile – causative agent for antibiotic-associated diarrhea from a hospital-acquired infection +• +Foodborne – Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy) +• +H. pylori – stomach ulcers +• +Respiratory – Group A Streptococcus , M. pneumoniae (Mycoplasma) and Bordetella pertussis , among tests for other diseases +• +Women’s Health & Sexually Transmitted Diseases (“STD”) – Group B Streptococcus , Chlamydia trachomatis , Neisseria gonorrhea , Herpes Simplex Virus Type 1 & Type 2 +Our diagnostics products also include Magellan’s LeadCare brand of tests for quantitative determination of blood lead levels. +Our product portfolio includes over 140 diagnostic tests and transport media, and is marketed to acute care hospitals, reference laboratories, outpatient +clinics and physician office laboratories in over 70 countries around the world. +- 7 - +Table of Contents +We continue to invest in new product development for our molecular testing platform, +illumi gene . This platform now has the following commercialized tests (assays): +1. +illumi gene C. difficile – commercialized in August 2010 +2. +illumi gene Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene Mycoplasma ( M. pneumoniae; walking pneumonia) – commercialized in June 2013 +5. +illumi gene Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene Chlamydia trachomatis – commercialized outside of U.S. in February 2015 +7. +illumi gene Neisseria gonorrhea – commercialized outside of U.S. in February 2015 +8. +illumi gene HSV 1&2 (Herpes Simplex Virus Type 1 & Type 2) – commercialized in July 2015 +9. +illumi gene Malaria – commercialized outside of U.S. in February 2016 +10. +illumi gene Mycoplasma Direct ( M. pneumoniae; walking pneumonia) – commercialized in June 2016 +We have several additional illumi gene tests in development, a robust pipeline of illumi gene opportunities and a plan +to continue adding new assays to our illumi gene platform menu. +We believe that our illumi gene system has been +well-accepted in our global markets. We now have over 1,500 customer account placements. Of these account placements, approximately 1,300 accounts have completed evaluations and validations and are regularly purchasing product, with the +balance of our account placements being in some stage of product evaluation and/or validation. Of our account placements, we have nearly 450 accounts that are regularly purchasing, evaluating and/or validating two or more assays. +Market Trends +The global market for infectious +disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. More importantly, within this market, there is a continuing shift from +conventional testing, which requires highly trained personnel and lengthy turnaround times for test results, to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The increasing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. With rapid and accurate +diagnoses of infectious diseases, physicians can pinpoint appropriate therapies quickly, leading to faster recovery, shorter hospital stays and lower overall treatment cost. Integrated Delivery Networks (IDNs) and Accountable Care Organizations +(ACOs) in our U.S. market have the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with IDNs, ACOs and health care systems that +are transitioning from fee-for-service compensation models, to value based reimbursement. Our C. difficile , Group B Streptococcus , Group A Streptococcus and H. pylori products are all examples of how a highly accurate +diagnostic test on the front end can mitigate or reduce down-stream costs for antibiotic use, symptom-relieving drugs and hospital stays. +- 8 - +Table of Contents +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing +organizations and integrated delivery networks, consolidation among reference laboratories, and acquisition of physician practices by hospitals, health systems, and for-profit specialty health care companies. We utilize multi-year supply agreements +to secure our business where we deem appropriate. +Cost containment pressures have also affected health care systems outside the U.S., particularly in +Europe, where the health care systems are generally government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing and Distribution +Our Diagnostics +segment’s sales and distribution network consists of the following for each of the broad geographic regions we serve: +North +America +In North America, our sales and distribution network consists of a direct sales force (U.S. only) complemented by independent +distributors. The use of independent distributors in the U.S. allows our products to reach any size health care facility and also provides our customers the option to purchase our products directly from Meridian or through an authorized +distributor. Two independent distributors in the U.S. accounted for 10% or more of consolidated net revenues in fiscal 2016, 2015 and 2014: Cardinal Healthcare Corporation and Thermo Fisher Scientific. Our revenues from Cardinal were +approximately $20,000, $29,000 and $28,000 during fiscal 2016, 2015 and 2014, respectively. Our revenues from Thermo Fisher were approximately $20,000, $25,000 and $23,000 during fiscal 2016, 2015 and 2014, respectively. +EMEA +In EMEA, our sales +and distribution network consists of direct sales forces in Belgium, France, Holland and Italy, and independent distributors in other European countries, Africa and the Middle East. We have implemented a direct sales presence in Germany and the +U.K. for our illumi gene products, and utilize independent distributors for our immunoassay products. We maintain a distribution center near Milan, Italy. +ROW +With the exception +of Australia, where we utilize a direct sales force, we utilize independent distributors throughout the ROW. +- 9 - +Table of Contents +Competition +Our major competitors in molecular diagnostics are Cepheid and Becton Dickinson, who have systems with multiple-assay menus. We also face competition in +molecular diagnostics, but to a lesser degree, from companies such as Alere, Great Basin, Nanosphere and Quidel. These latter companies have a limited commercial menu and tend to compete strictly on price. We believe that our molecular +platform offers a number of competitive features: +• +Molecular assay sensitivity that is comparable to higher costing PCR; +• +Low capital investment with no instrument service cost; +• +Small footprint that is portable and does not consume much laboratory space; and +• +Product menu that fits with initiatives to improve clinical and economic outcomes. +Our major competitors in +rapid immunoassay diagnostics are primarily Alere and Quidel. These companies tend to compete strictly on price. For blood lead testing, we believe we have the only FDA-cleared, CLIA-waived point-of-care test available +commercially. Other blood lead testing systems in use include Graphite Furnace Atomic Absorption Spectroscopy, which requires a highly-skilled technician and larger laboratory space to operate, in addition to not being portable or suitable for +point-of-care use. We believe that with the breadth and depth of our product portfolio, we are well positioned for the clinical laboratory. +Research and Development +Our Diagnostics +segment’s research and development organization for infectious disease products is located at our corporate headquarters in Newtown, Ohio, a suburb of Cincinnati, and has expertise in biochemistry, immunology, mycology, bacteriology, virology, +parasitology, and molecular biology. Our Magellan business has a dedicated research and development team in Billerica, Massachusetts. Research and development expenses for the Diagnostics segment for fiscal 2016, 2015 and 2014 were +approximately $11,000, $10,000 and $10,000, respectively. Our research and development activities are focused on new product and new technology development, new applications for our existing technologies, and improvements to existing +products. Research and development efforts may occur in-house or with collaborative partners. We believe that new product development is a key source for sustaining revenue growth. The products within our +illumi gene molecular platform, H. pylori product family and blood lead testing family were developed solely in-house, or substantially so. +Manufacturing +Our immunoassay and molecular +products require the production of highly specific and sensitive antigens, antibodies, primers and enzymes. While we produce substantially all of our own requirements including monoclonal and polyclonal antibodies, and a variety of fungal, +bacterial and viral antigens, currently a number of the raw materials used in our products, including our illumi gene molecular products, are purchased from outside vendors. With the expansion of our molecular diagnostic +manufacturing capacity at our Cincinnati, Ohio location in recent years, we brought in-house certain molecular component manufacturing that was previously outsourced. Our blood lead testing products require the production of electrical chemical +sensors, for which we produce all of our own requirements. We believe that we have sufficient manufacturing and sourcing capacity for anticipated growth over the next several years. +- 10 - +Table of Contents +Intellectual Property, Patents and Licenses +We own or license U.S. and foreign patents, most of which are for selected products manufactured by our Diagnostics segment. These patents are used in our +manufacturing processes for selected products (method patents) or may relate to the design of the test device technology format (design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully +replicate our production and manufacturing technologies and processes. Our employees are required to sign confidentiality and non-disclosure agreements designed to protect our proprietary products. +The patents for our illumi gene products, which represented 20% and 21% of consolidated revenues for fiscal 2016 and fiscal 2015, +respectively, are licensed from a third party, Eiken Chemical Co., Ltd., under a non-exclusive license agreement and expire between 2020 and 2022. These patents were issued in the U.S., European Community and other countries. The term +of our license agreement runs until the last patent expires in 2022, at which point we will be free to practice the patents without any restriction or royalty obligation. +The patents for our H. pylori products, which represented 15% and 14% of consolidated revenues for fiscal 2016 and fiscal 2015, respectively, are +owned by us and expired in May 2016 in the U.S., and will expire in fiscal 2017 in countries outside the U.S. We expect competition with respect to our H. pylori products to increase in fiscal 2017 as we currently market the only +FDA-cleared tests to detect H. pylori antigen in stool samples. Such competition may have an adverse impact on our selling prices for these products or our ability to retain business at prices acceptable to us, and consequently, +adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to mitigate competition, our product development pipeline includes multiple new product initiatives for the detection of H. +pylori . We are unable to provide assurances that we will be successful with any mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and +gross profit. +Government Regulation +Our +diagnostic products are regulated by the Food & Drug Administration (FDA) as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (FDCA). Under the FDCA, medical devices are classified into one of three classes (i.e., +Class I, II or III). Class I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally must receive “pre-market approval” from the FDA as to safety and +effectiveness. +- 11 - +Table of Contents +Each of the diagnostic products currently marketed by us in the United States has been cleared by the FDA +pursuant to the 510(k) clearance process or is exempt from such requirements. We believe that most, but not all, products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all +Class II devices, will be eligible for 510(k) clearance; however, we can make no assurances in this regard. Meridian’s TRU FLU rapid influenza assay was cleared in 2006 as a Class I device. In May 2014, the FDA proposed reclassifying +rapid influenza assays as a Class II device, requiring the submission of a new 510(k) application and subjecting TRU FLU and similar competitive devices to increased requirements for sensitivity. If the proposed rule becomes effective, Meridian +will have one year to bring its assay up to the new requirements or remove it from the market. Sales of the TRU FLU product totaled approximately $1,000 in fiscal 2016. +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, largely similar to that of the FDA. +Meridian’s Cincinnati manufacturing facility is certified to ISO 13485:2012, and the Magellan facility in Billerica, Massachusetts is certified to ISO +9001:2008 and ISO 13485:2003. +Medical Device Tax +On January 1, 2013, the medical device tax established as part of the U.S. health care reform legislation became effective and as a result, the Company made +its first required tax deposit near the end of January 2013. During fiscal 2016, 2015 and 2014, the Company recorded to cost of sales approximately $500, $1,900 and $1,750, respectively, of medical device tax expense related to this +legislation. During December 2015, the Consolidations Appropriations Act of 2016 imposed a two-year moratorium on this excise tax effective January 1, 2016. During calendar years 2016 and 2017, this moratorium would result in approximately +$2,000 of savings each year. We are unable to predict any future legislative changes or developments related to this moratorium or excise tax. +Seasonal Factors and Sporadic Outbreaks +Our +principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory, and parasitic infectious diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in +nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as the H1N1 influenza outbreak during fiscal 2009. While we believe that the breadth of our diagnostic product lines reduces the risk +that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be impacted period over period by such factors. +- 12 - +Table of Contents +Life Science Segment +Overview of Products and Markets +Our Life Science +segment’s business focuses on the development, manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers, agri-bio companies and other +diagnostic manufacturing companies. Third-party revenues for this segment were approximately $51,000, $49,000 and $47,000 for fiscal 2016, 2015 and 2014, respectively. As of September 30, 2016, our Life Science segment had approximately +210 employees in seven countries. +Most of the revenues for our Life Science segment currently come from the manufacture, sale and distribution of bulk +antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies focused on the development of immunoassay and molecular tests. Approximately 65% of +Life Science revenues are generated from the industrial market, defined as diagnostic manufacturers and the agriculture industry. This continues to be an increasing focus of our Bioline molecular component business, which historically focused +on the academic/research market that comprises the remaining 35% of Life Science revenues. We utilize direct sales teams in key countries such as the U.S., the U.K., Germany, France, Australia and Singapore. Opened in 2013, the Singapore +sales and business development office is designed to increase our presence and our revenue opportunities in Asia for both molecular and immunoassay components. Additionally, in order to further pursue revenue opportunities in Asia, and China in +particular, during fiscal 2015 we opened a representative office in Beijing, China. We utilize a network of distributors in other major countries. During fiscal 2016, 18% of third-party revenues for this segment were from two diagnostic +manufacturing customers. +Products such as antibodies, antigens and reagents are marketed primarily to diagnostic manufacturing customers as a source of +raw materials for their immunoassay products, or as an outsourced step in their manufacturing processes. For example, we supply a number of major diagnostic manufacturers with proteins used to detect hepatitis A and rubella. These products +are typically sold in bulk quantities, and may also be custom-designed for a particular manufacturer’s requirements. Sales efforts are focused on multi-year supply arrangements in order to provide stability in volumes and pricing. We +believe this benefits both us and our customers. +Molecular biology products such as PCR/qPCR reagents, nucleotides and competent cells are marketed to +academic/research and industrial customers. These products are used in measuring DNA and RNA in clinical and agricultural applications. These reagents improve the purity, yield and speed of PCR reactions. Products such as MyTaq and SensiFAST are examples of this type of PCR/qPCR reagent. +- 13 - +Table of Contents +Market Trends +As certain global markets become increasingly accessible to us, most notably China, geographic expansion continues to be a significant strategy for our Life +Science segment, along with further penetration into industrial markets with our molecular products. +Competition +The market for bulk biomedical reagents is highly competitive. Important competitive factors include product quality, price, customer service and +reputation. We face competitors, many of which have greater financial, research and development, sales and marketing, and manufacturing resources, and where sole-source supply arrangements do not exist. Customers also may choose to +manufacture their biomedical reagents in-house rather than purchase from outside vendors such as Meridian. +The academic/research market is highly +fragmented. Individual purchases are typically of small quantities. The breadth of product offerings, quality, price and service, including on-line capabilities and technical resources, are important factors to building customer loyalty +and repeat purchases. +Research and Development +Research and development expenses for our Life Science segment for each of fiscal 2016, 2015 and 2014 were approximately $3,000. The primary focus of this +research and development organization is development of new molecular reagent products. +Manufacturing and Government Regulation +Our Life Science U.S. facilities are ISO 9001:2008 certified and our Bioline facilities in the U.K. and Germany are ISO 13485:2012 +certified. Additionally, where appropriate, our Life Science facilities comply with Regulation EC 1069:2009. +Acquisitions +Acquisitions have played an important role in the growth of our businesses. Our acquisition objectives include, among other things: (i) enhancing product +offerings; (ii) improving product distribution capabilities; (iii) providing access to new markets; and/or (iv) providing access to key biologicals or new technologies that lead to new products. Although we cannot provide assurance that we will +consummate additional acquisitions in the future, nor can we provide assurance that any acquisitions will accomplish these objectives, we expect that the potential for acquisitions will continue to provide opportunities for revenue and earnings +growth in the future. +As previously noted in the Overview section, during March 2016, we acquired all of the outstanding common stock of +Magellan. Headquartered near Boston, Massachusetts, Magellan is a leading manufacturer of FDA-cleared products for the testing of blood to diagnose lead poisoning in children and adults. Magellan is the leading provider of point-of-care +lead testing systems in the U.S. +- 14 - +Table of Contents +International Markets +International markets are an important source of revenues and future growth opportunities for both of our segments. For both segments combined, revenues +from customers located outside of the Americas approximated $52,000 or 26% of consolidated fiscal 2016 revenues, $49,000 or 25% of consolidated fiscal 2015 revenues, and $55,000 or 29% of consolidated fiscal 2014 revenues. We expect to continue +to look to international markets as a source of revenue growth in the future. +During fiscal 2016, currency exchange had an approximate $1,700 unfavorable +impact on revenues; $700 within the Diagnostics segment and $1,000 within the Life Science segment. This compares to currency exchange rates having an approximate $4,700 unfavorable impact on revenues in fiscal 2015; $3,200 within the +Diagnostics segment and $1,500 within the Life Science segment. Due to natural hedge relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net earnings was not significant +during fiscal 2016, 2015 or 2014. +Environmental +We +are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. +ITEM 1A. +RISK FACTORS +In addition to the other information set forth in this report, you should carefully consider the following factors, which could +materially affect our business, financial condition, cash flows or future results. Any one of these factors could cause our actual results to vary materially from recent results or from anticipated future results. The risks described below +are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. +Risks Affecting Growth and Profitability of our Business +We may be unable to develop new products and services or acquire products and services on favorable terms. +The medical diagnostic and life science industries are characterized by ongoing technological developments and changing customer requirements. As such, our +results of operations and continued growth depend, in part, on our ability in a timely manner to develop or acquire rights to, and successfully introduce into the marketplace, enhancements of existing products and services or new products and +services that incorporate technological advances, meet customer requirements and/or respond to products developed by our competition. We cannot provide any assurance that we will be successful in developing or acquiring such rights to products and +services on a timely basis, or that such products and services will adequately address the changing needs of the marketplace, either of which could adversely affect our results of operations. +- 15 - +Table of Contents +In addition, we must regularly allocate considerable resources to research and development of new products, +services and technologies. The research and development process generally takes a significant amount of time from design stage to product launch. This process is conducted in various stages. During each stage, there is a risk that we +will not achieve our goals on a timely basis, or at all, and we may have to abandon a product in which we have invested substantial resources. +We +may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions we make. +One of our growth strategies is +the acquisition of companies and/or products. Although additional acquisitions of companies and products may enhance the opportunity to increase net earnings over time, such acquisitions could result in greater administrative burdens, increased +exposure to the uncertainties inherent in marketing new products, and financial risks of additional operating costs. The principal benefits expected to result from any acquisitions we make will not be achieved fully unless we are able to +successfully integrate the operations of the acquired entities with our operations and realize the anticipated synergies, cost savings and growth opportunities from integrating these businesses into our existing businesses. We cannot provide +assurance that we will be able to identify and complete additional acquisitions on terms we consider favorable or that, if completed, will be successfully integrated into our operations. +Revenues for our Diagnostics segment may be impacted by our reliance upon two key distributors in North America, seasonal factors and sporadic +outbreaks, and changing diagnostic market conditions. +Key Distributors +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 27% and 37%, respectively, of the Diagnostics segment’s total +revenues for fiscal 2016 and fiscal 2015, or 20% and 28%, respectively, of our consolidated revenues for fiscal 2016 and fiscal 2015. These parties distribute our products and other laboratory products to end-user customers. The loss of either +of these distributors could negatively impact our revenues and results of operations unless suitable alternatives were timely found or lost sales to one distributor were absorbed by another distributor. Finding a suitable alternative on +satisfactory terms may pose challenges in our industry’s competitive environment. As an alternative, we could expand our efforts to distribute and market our products directly. This alternative, however, would require substantial +investment in additional sales, marketing and logistics resources, including hiring additional sales and customer service personnel, which would significantly increase our future selling, general and administrative expenses, but would not +necessarily result in lower net income levels. +- 16 - +Table of Contents +In addition, buying patterns of these two distributors may fluctuate from quarter to quarter, potentially leading +to uneven concentration levels on a quarterly basis. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory, and parasitic infectious +diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as H1N1 influenza. While we believe that +the breadth of our diagnostic product lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be negatively +impacted period over period by such factors. +Changing Diagnostic Market Conditions +Changes in the U.S. health care delivery system have resulted in consolidation among reference laboratories and the formation of multi-hospital alliances, +reducing the number of institutional customers for diagnostic test products. Consolidation in the U.S. health care industry has also led to the creation of group purchasing organizations (GPOs) and integrated delivery networks (IDNs) that +aggregate buying power for hospital groups and put pressure on our selling prices. Due to such consolidation, we may not be able to enter into and/or sustain contractual or other marketing or distribution arrangements on a satisfactory +commercial basis with institutional customers, GPOs and IDNs, which could adversely affect our results of operations. +We could be adversely +affected by health care reform legislation. +Third-party payers for medical products and services, including state, federal and foreign +governments, are increasingly concerned about escalating health care costs and can indirectly affect the pricing or the relative attractiveness of our products by regulating the maximum amount of reimbursement they will provide for diagnostic +testing services. Following years of increasing pressure, during 2010 the U.S. government enacted comprehensive health care reform. Although to date, we have not seen any significant effect on the reimbursement rates for our products, if +reimbursement amounts for diagnostic testing services are decreased in the future, such decreases may reduce the amount that will be reimbursed to hospitals or physicians for such services and consequently, could place constraints on the levels of +overall pricing, which could have a material effect on our revenues and/or results of operations. +In addition, on January 1, 2013, the medical device tax +established as part of the U.S. health care reform legislation became effective and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2016, 2015 and 2014, the Company recorded approximately +$500, $1,900 and $1,750, respectively, of Medical Device Tax expense, which is reflected as a component of cost of sales in the accompanying Consolidated Statements of Operations. During December 2015, the Consolidations Appropriations Act of +2016 imposed a two-year moratorium on this excise tax effective January 1, 2016. During calendar years 2016 and 2017, this moratorium would result in approximately $2,000 of savings each year. We are unable to predict any future +legislative changes or developments related to this moratorium or excise tax. +- 17 - +Table of Contents +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +As part of the Budget Control Act passed in August 2011 to extend the federal debt limit and reduce government spending, $1.2 trillion in automatic spending +cuts (known as sequestration) were implemented in 2013. The sequestration requires a 2% cut in Medicare payments for all services, including our diagnostic tests, which, due to subsequent legislative amendments to the statute, will remain in +effect through 2024 unless Congressional action is otherwise taken. Government research funding has also been reduced as a result of the sequestration. On January 2, 2013, the American Taxpayer Relief Act of 2012 also was signed into law, +which, among other things, further reduces Medicare payments to providers such as hospitals, imaging centers and cancer treatment centers, and increases the statute of limitations period for the government to recover overpayments to providers from +three to five years. +Such reductions in government health care spending or research funding could result in reduced demand for our products or additional +pricing pressure. Further, there is ongoing uncertainty regarding the federal budget and federal spending levels, including the possible impacts of a failure to increase the “debt ceiling.” Any U.S. government default on its debt could +have broad macroeconomic effects that could, among other things, raise our borrowing costs. Any future shutdown of the federal government or failure to enact annual appropriations could also have a material adverse impact on our business. +Revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two diagnostic manufacturing customers were 18% and 16% of the Life +Science segment’s total revenues for fiscal 2016 and fiscal 2015, respectively; and 5% and 4% of our consolidated revenues for fiscal 2016 and fiscal 2015, respectively. Our Life Science segment has four other significant customers who +purchase antigens, antibodies and reagents, which together comprised 8% and 10% of the segment’s total revenues for fiscal 2016 and fiscal 2015, respectively. Any significant alteration of buying patterns from these customers could +adversely affect our period over period revenues and results of operations. +Intense competition could adversely affect our profitability. +The markets for our products and services are characterized by substantial competition and rapid change. Hundreds of companies around the world +supply diagnostic tests and immunoassay and molecular reagents. These companies range from multinational health care entities, for which diagnostics is one line of business, to small start-up companies. Many of our competitors have +significantly greater financial, technical, manufacturing and marketing resources than we do. We cannot provide assurance that our products and services will be able to compete successfully with the products and services of our competitors. +- 18 - +Table of Contents +We may face increased competition resulting from expiration of our H. pylori patents. +The patents for our H. pylori products are owned by us and expired in May 2016 in the U.S., and will expire in fiscal 2017 in countries outside the +U.S. We expect competition with respect to our H. pylori products to increase in fiscal 2017 as we currently market the only FDA-cleared tests to detect H. pylori antigen in stool samples. Such competition may have an adverse +impact on our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to +mitigate any loss in revenues, among other things, we are researching and experimenting with new products and attempting to secure significant customers under long-term contracts. We are unable to provide assurances that we will be successful with +any mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and gross profit. +We depend on international revenues, and our financial results may be adversely impacted by foreign currency, regulatory or other developments affecting +international markets. +We sell products and services into approximately 70 countries. Approximately 26% and 25% of our net revenues for +fiscal 2016 and 2015, respectively, were attributable to markets outside of the Americas. For fiscal 2016, approximately 35% of our international revenues were from sales made in Euros and 40% were from sales made in U.S. dollars, with the remaining +25% primarily being a combination of sales made in British pounds, Australian dollars and Singapore dollars. We are subject to the risks associated with fluctuations in the exchange rates for the Australian dollar, British pound, Euro and +Singapore dollar to the U.S. dollar. We are also subject to other risks associated with international operations, including longer customer payment cycles, tariff regulations, requirements for export licenses, instability of foreign +governments, and governmental requirements with respect to the importation and distribution of medical devices and immunodiagnostic and molecular biology reagents, all of which may vary by country. +Risks Affecting our Manufacturing Operations +We +are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +Medical device diagnostics is a +highly regulated industry. We cannot provide assurance that we will be able to obtain necessary governmental clearances or approvals or timely clearances or approvals to market future products in the United States and other countries. Costs and +difficulties in complying with laws and regulations administered by the U.S. Food and Drug Administration, the U.S. Department of Agriculture, the U.S. Department of Commerce, the U.S. Drug Enforcement Agency, the Centers for Disease Control or +other regulators can result in unanticipated expenses and delays and interruptions to the sale of new and existing products. +- 19 - +Table of Contents +Regulatory approval can be a lengthy, expensive and uncertain process, making the timing and costs of approvals +difficult to predict. The failure to comply with these regulations can result in delays in obtaining authorization to sell products, seizure or recall of products, suspension or revocation of authority to manufacture or sell products, and other +civil or criminal sanctions. +Significant interruptions in production at our principal manufacturing facilities and/or third-party manufacturing +facilities would adversely affect our business and operating results. +Products and services manufactured at facilities we own or lease comprised a +majority of our revenues. Our global supply of these products and services is dependent on the uninterrupted and efficient operation of these facilities. In addition, we currently rely on a small number of third-party manufacturers to +produce certain of our diagnostic products and product components. The operations of our facilities or these third-party manufacturing facilities could be adversely affected by power failures, natural or other disasters, such as earthquakes, +floods, tornadoes or terrorist threats. Although we carry insurance to protect against certain business interruptions at our facilities, there can be no assurance that such coverage will be adequate or that such coverage will continue to remain +available on acceptable terms, if at all. Any significant interruption in the Company’s or a third-party supplier’s manufacturing capabilities could materially and adversely affect our operating results. +We depend on sole-source suppliers for certain critical raw materials and components, and finished products. A supply interruption could adversely +affect our business. +Raw Materials and Components +Our diagnostic products are made from a wide variety of raw materials that are biological or chemical in nature, and that generally are available from multiple +sources of supply. We sole-source certain raw materials and components, which make it time consuming and costly to switch raw materials and components in FDA-cleared products. If certain suppliers fail to supply required raw materials or +components, we will need to secure other sources which may require us to conduct additional development and testing and obtain regulatory approval. These activities require significant time and resources, and there is no assurance that new sources +will be secured or regulatory approvals, if necessary, will be obtained. +We utilize third-party manufacturers for our instrumentation. One third +party manufactures our proprietary illumi pro-10 Incubator/Reader (instrument), a component of our illumi gene molecular system, and a separate third party manufactures our proprietary LeadCare +instruments. These instruments are manufactured exclusively for Meridian according to our specifications. While other manufacturers for these types of instruments are available, we source solely from one manufacturer to limit the costs +involved in clearing the system for marketing in the United States. If these third-party manufacturers fail to supply us with instruments, we will need to secure another manufacturer, and it may take as long as 12 months to transfer instrument +manufacturing. An interruption in the manufacturing of these instruments could have a material adverse effect on our operating results. +- 20 - +Table of Contents +Additionally, one third party manufactures one certain reagent for use with our illumi gene +assays. While alternative suppliers exist, we elect to utilize this third party exclusively in order to maintain consistency in our materials, which is critical in complying with FDA regulatory requirements. +Finished Products +We outsource the manufacturing for +certain finished diagnostic products to third parties. A disruption in the supply of these finished products could have a material adverse effect on our business until we find another supplier or bring manufacturing in-house. +Four products manufactured exclusively for us by two separate and independent companies accounted for 12%, 15% and 14% of consolidated revenues in fiscal +2016, 2015 and 2014, respectively. Meridian owns all rights and title to the FDA 510(k) clearances for these products. +Activities undertaken by +Meridian to reduce the risk of these sole-supplier arrangements include maintaining adequate inventory levels, supplier qualification procedures, supplier audits, site visits and frequent communication. Additionally, we have identified potential +alternate suppliers. +Risks Related to Intellectual Property and Product Liability +We may be unable to protect or obtain proprietary rights that we utilize or intend to utilize. +In developing and manufacturing our products, we employ a variety of proprietary and patented technologies. In addition, we have licensed, and expect to +continue to license, various complementary technologies and methods from academic institutions and public and private companies. We cannot provide assurance that the technologies that we own or license provide protection from competitive threats or +from challenges to our intellectual property. In addition, we cannot provide assurances that we will be successful in obtaining and retaining licenses or proprietary or patented technologies in the future. +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Litigation over intellectual property rights is prevalent in the diagnostic industry. As the market for diagnostics continues to grow and the number of +participants in the market increases, we may increasingly be subject to patent infringement claims. It is possible that a third party may claim infringement against us. If found to infringe, we may attempt to obtain a license to such +intellectual property; however, we may be unable to do so on favorable terms, or at all. Additionally, if our products are found to infringe on third-party intellectual property, we may be required to pay damages for past infringement and lose +the ability to sell certain products, causing our revenues to decrease. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability and the damage to our reputation in the industry +could have a material adverse effect on our business. +- 21 - +Table of Contents +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and +may have to limit or cease sales of our products. +The testing, manufacturing and marketing of medical diagnostic products involves an inherent +risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We currently carry product +liability insurance at a level we believe is commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. In certain customer contracts, we indemnify third parties for certain product +liability claims related to our products. These indemnification obligations may cause us to pay significant sums of money for claims that are covered by these indemnifications. In addition, a defect in the design or manufacture of our +products could have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect +on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our business. +Other Risks Affecting Our +Business +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +Our future success depends on our continued ability to attract, hire and retain highly qualified personnel, including our executive officers and scientific, +technical, sales and marketing employees, and their ability to manage growth successfully. If such key employees were to leave and we were unable to obtain adequate replacements, our operating results could be adversely affected. +Our bank credit agreements impose restrictions with respect to our operations. +Our bank credit agreements contain a number of financial covenants that require us to meet certain financial ratios and tests. If we fail to comply with +the obligations in the credit agreements, we would be in default under the credit agreements. If an event of default is not cured or waived, it could result in acceleration of any indebtedness under our credit agreements, which could have a +material adverse effect on our business. At September 30, 2016, we have approximately $59,000 outstanding on a five-year term loan entered into in connection with the Magellan acquisition and no borrowings are outstanding under our $30,000 bank +revolving credit facility. +- 22 - +Table of Contents +We face risks related to global economic conditions. +We currently generate significant operating cash flows, which combined with access to the credit markets, provides us with discretionary funding capacity for +research and development and other strategic activities. However, as an enterprise with global operations and markets, our operations and financial performance are in part dependent upon global economic conditions, and we could be negatively +impacted by a global, regional or national economic crisis, including sovereign risk in the event of deterioration in the credit worthiness of or a default by local governments. We are particularly susceptible to the economic conditions in +countries where government-sponsored health care systems are the primary payers for health care, including those countries within the European Union that are reducing their public expenditures in an effort to achieve cost savings. The +uncertainty in global economic conditions poses a risk to the overall economy that could impact demand for our products, as well as our ability to manage normal commercial relationships with our customers, suppliers and creditors, including +financial institutions. As such, if global economic conditions deteriorate significantly, our business could be negatively impacted, including such areas as reduced demand for our products from a slow-down in the general economy, supplier or +customer disruptions resulting from tighter credit markets, and/or temporary interruptions in our ability to conduct day-to-day transactions through our financial intermediaries involving the payment to or collection of funds from our customers, +vendors and suppliers. While to-date such factors have not had a significant negative impact on our results or operations, we continue to monitor and plan for the potential impact of these global economic factors. +On June 23, 2016, the United Kingdom voted to leave the European Union (commonly referred to as “Brexit”) and while the impact of Brexit remains +uncertain, the resulting immediate changes in foreign currency exchange rates has limited overall impact due to natural hedging. However, any predicted deterioration in the United Kingdom and European economic outlook may have an adverse effect on +revenue growth, but the extent of such effect cannot yet be quantified. In the longer term, it is highly likely we will be directly impacted in a number of key areas including the hiring and retention of qualified staff, regulatory affairs, +manufacturing and logistics. We are closely monitoring the Brexit developments in order to determine, quantify and proactively address changes as they become clear. Despite the Brexit developments, we do not expect macroeconomic conditions +to have a significant impact on our liquidity needs, financial condition or results of operations, although no assurances can be made in this regard. We intend to continue to fund our working capital requirements and dividends from current cash +flows from operating activities and cash on hand. If needed, we also have an additional source of liquidity through our $30,000 bank revolving credit facility. Our liquidity needs may change if overall economic conditions change and/or +liquidity and credit within the financial markets tightens for an extended period of time, and such conditions impact the collectibility of our customer accounts receivable or impact credit terms with our vendors, or disrupt the supply of raw +materials and services. +Breaches of our information technology systems could have a material adverse effect on our operations. +We rely on information technology systems to process, transmit and store electronic information in our day-to-day operations. Like many multinational +corporations, our information technology systems may be subjected to computer viruses or other malicious codes, unauthorized access attempts, and cyber- or phishing-attacks. We also store certain information with third parties that could be subject +to these types of attacks. Such attacks could result in our intellectual property and other confidential information being lost or stolen, disruption of our operations, and other negative consequences, such as increased costs for security measures +or remediation costs, and diversion of management attention. While we will continue to implement additional protective measures to reduce the risk of and detect cyber incidents, cyber-attacks are becoming more sophisticated and frequent, and the +techniques used in such attacks change rapidly. There can be no assurances that our protective measures will prevent attacks that could have a significant impact on our business. +- 23 - +Table of Contents +Natural disasters, war and other events could adversely affect our future revenues and operating income. +Natural disasters (including pandemics), war, terrorism, labor disruptions and international conflicts, and actions taken by the United States and +other governments or by our customers or suppliers in response to such events, could cause significant economic disruption and political and social instability in the United States and in areas outside of the United States in which we operate. These +events could result in decreased demand for our products, adversely affect our manufacturing and distribution capabilities, or increase the costs for, or cause interruptions in, the supply of materials from our suppliers. +Risks Related to Our Common Stock +Our board of directors +has the authority to issue up to 1,000 shares of undesignated preferred stock and to determine the rights, preferences, privileges and restrictions, including voting rights, of such shares without any future vote or action by the +shareholders. The issuance of preferred stock under certain circumstances could have the effect of delaying or preventing a change in control of our company. Ohio corporation law contains provisions that may discourage takeover bids for +our company that have not been negotiated with the board of directors. Such provisions could limit the price that investors might be willing to pay in the future for shares of our common stock. In addition, sales of substantial amounts of +such shares in the public market could adversely affect the market price of our common stock and our ability to raise additional capital at a price favorable to us. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Our +corporate offices, Diagnostics manufacturing facility and Diagnostics research and development facility are located in five buildings totaling approximately 120,000 square feet on 10 acres of land in the Village of Newtown, a suburb of Cincinnati, +Ohio. These properties are owned by us. Magellan’s operations are headquartered in an approximately 23,000 square foot leased facility in Billerica, Massachusetts, in which it conducts manufacturing, research and development, sales, +and administrative activities. We also operate a Diagnostics sales and distribution center near Milan, Italy in an approximately 18,000 square foot building. This facility is owned by our wholly-owned Italian subsidiary, Meridian +Bioscience Europe s.r.l. We also rent office space in Paris, France and Braine-l’Alleud, Belgium for sales and administrative functions. +- 24 - +Table of Contents +Our Life Science operations are conducted in several facilities in Memphis, Tennessee; Boca Raton, Florida; +Taunton, Massachusetts; London, England; Luckenwalde, Germany; Sydney, Australia; Singapore; and Beijing, China. Our facility in Memphis, Tennessee consists of two buildings totaling approximately 44,000 square feet and is owned by us. Our +leased facility in Boca Raton, Florida contains approximately 7,500 square feet of manufacturing space. Following are details of our other Life Science facilities, all of which are leased: Taunton – approximately 10,000 square feet of +sales and warehouse space; London – approximately 20,000 square feet of sales, warehouse, distribution, research and development, manufacturing and administrative office space; Luckenwalde – approximately 10,000 square feet of sales, +warehouse and manufacturing space; Sydney – approximately 5,000 square feet of sales, warehouse, research and development, and manufacturing space; Singapore – approximately 2,000 square feet of sales and business development space; +Beijing – less than 1,000 square feet of representative office space maintained for business development purposes. +ITEM 3. +LEGAL PROCEEDINGS +We are a party to various litigation matters that we believe are in the normal course of business. The ultimate resolution of these matters is not +expected to have a material adverse effect on our financial position, results of operations or cash flows. No material provision has been made in the accompanying consolidated financial statements for these matters. +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +- 25 - +Table of Contents +PART II. +ITEM 5. +MARKET FOR REGISTRANT’S COMMON +EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Refer to “Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on Pages 15 through 24 +of this Annual Report. +“Common Stock Information” on the inside back cover of the Annual Report to Shareholders for fiscal 2016 and +“Quarterly Financial Data (Unaudited)” relating to our dividends in Note 10 to the Consolidated Financial Statements are incorporated herein by reference. Except as may otherwise be prohibited by applicable law, there are no +restrictions on cash dividend payments. +During fiscal 2016, our indicated annual dividend rate of $0.80 per share approximated 105% of full year diluted +earnings per share (approximately 100% excluding the effect of costs related to acquisition activities and restructuring our sales and marketing leadership), exceeding our long-standing policy of establishing a cash dividend payout ratio of between +75% and 85% of each fiscal year’s expected net earnings. Despite there being certain individual fiscal years in which our payout ratio has fallen outside of this policy range, since adopting this policy in November 2002, our cumulative +cash dividend payout has only slightly exceeded this range, approximating 86% of cumulative net earnings during this timeframe. The declaration and amount of dividends will be determined by the board of directors in its discretion based upon +its evaluation of earnings, cash flow requirements and future business developments and opportunities, including acquisitions. At its meeting on November 9, 2016, the board of directors announced a continuation of the $0.80 indicated annual +dividend rate per share for fiscal 2017. We paid dividends of $0.80 per share in fiscal 2016, $0.80 per share in fiscal 2015 and $0.79 per share in fiscal 2014. +As of September 30, 2016, there were approximately 525 holders of record and approximately 17,700 beneficial owners of our common shares. +ITEM 6. +SELECTED FINANCIAL DATA +Incorporated by reference from inside front cover of the Annual Report to Shareholders for 2016. +- 26 - +Table of Contents +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Refer to “Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on Pages 15 through 24 +of this Annual Report. +In the discussion that follows, all amounts are in thousands (both tables and text), except per share data . +Results of Operations: +Highlights +As more fully detailed below, fiscal 2016 was highlighted by our March 24, 2016 acquisition of Magellan Biosciences, Inc., and its wholly-owned +subsidiary Magellan Diagnostics, Inc. (collectively, “Magellan”). Headquartered near Boston, Massachusetts, Magellan is a leading manufacturer of FDA-cleared products for the testing of blood to diagnose lead poisoning in children and +adults. Magellan is the leading provider of point-of-care lead testing systems in the U.S. +In addition, during the year we (i) commercialized our +illumi gene Malaria product outside of the U.S.; and (ii) commercialized our illumi gene Mycoplasma Direct product in the U.S. – representing the ninth and tenth assays for our +illumi gene molecular platform menu. +Fourth Quarter +Net earnings for the fourth quarter of fiscal 2016 decreased 35% to $5,491, or $0.13 per diluted share, from net earnings for the fourth quarter of fiscal 2015 +of $8,467, or $0.20 per diluted share. These fourth quarter results included $677 of costs associated with the restructuring of our sales and marketing leadership (impact on net earnings of $431, or $0.01 per diluted share). Consolidated +revenues for the fourth quarter of fiscal 2016 totaled $46,998, remaining relatively flat compared to the fourth quarter of fiscal 2015; increasing 1% on a constant-currency basis. +Revenues for the Diagnostics segment for the fourth quarter of fiscal 2016 remained flat compared to the fourth quarter of fiscal 2015 (increasing 1% on a +constant-currency basis), comprised of a 15% decrease in molecular products and a 7% increase in non-molecular products, including $5,282 of Magellan revenues. With a 2% increase in its molecular components business and a 4% decline in its +immunoassay components business, revenues for our Life Science segment decreased 2% in the fourth quarter of fiscal 2016 compared to the fourth quarter of fiscal 2015. On a constant-currency basis, revenues for our Life Science Segment were +flat. +- 27 - +Table of Contents +The fourth quarter revenues reflect a combination of ongoing competitive pressures within the C. difficile +and foodborne product families, distributor order patterns and the timing of respiratory season stocking orders within the core diagnostics business – offset by the positive effects of continued growth in our H. pylori product family and +the addition of Magellan revenues. +Fiscal Year +Net earnings for fiscal 2016 decreased 9% to $32,229, or $0.76 per diluted share, from net earnings for fiscal 2015 of $35,540, or $0.85 per diluted +share. Fiscal 2016 results included $677 of costs associated with the restructuring of our sales and marketing leadership and $1,481 of costs associated with our acquisition activities (combined impact on net earnings of $1,664, or $0.04 per +diluted share). Consolidated revenues increased 1% to $196,082 for fiscal 2016 compared to fiscal 2015, and also increased 1% on a constant-currency basis. +In fiscal 2016, revenues for the Diagnostics segment decreased 1% compared to fiscal 2015 and were flat on a constant-currency basis, comprised of a 6% +decrease in molecular products and a 1% increase in non-molecular products, including $10,034 of Magellan revenues. With flat revenues in its molecular components business and an 8% increase in its immunoassay components business, revenues of our +Life Science segment increased 5% during fiscal 2016 compared to fiscal 2015. Revenues increased 7% on a constant-currency basis. +REVENUE +OVERVIEW +Below are analyses of the Company’s revenue, provided for each of the following: +• +By Reportable Segment & Geographic Region +• +By Product Platform/Type +Revenue Overview- By Reportable Segment & Geographic Region +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations for infectious disease products in +Cincinnati, Ohio and, as a result of the acquisition of Magellan, manufacturing operations for products detecting elevated lead levels in blood in Billerica, Massachusetts (near Boston). These diagnostic test products are sold and distributed +in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, or “ROW”). The Life +Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, +nucleotides, competent cells, and bioresearch reagents domestically and abroad, including sales and business development offices in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. +- 28 - +Table of Contents +Revenues for the Diagnostics segment, in the normal course of business, may be affected from quarter to quarter +by buying patterns of major distributors, seasonality and strength of certain diseases, and foreign currency exchange rates. Revenues for the Life Science segment, in the normal course of business, may be affected from quarter to quarter by +buying patterns of major customers, and foreign currency exchange rates. We believe that the overall breadth of our product lines serves to reduce the variability in consolidated revenues due to these factors. +Revenues for each of our segments and the geographic regions therein are shown below. +2016 vs. +2015 +2015 vs. +2014 +2016 +2015 +2014 +Inc (Dec) +Inc (Dec) +Diagnostics- +Americas +$ +123,714 +$ +123,366 +$ +114,754 +— +% +8 +% +EMEA +18,424 +19,135 +21,807 +(4 +)% +(12 +)% +ROW +2,976 +3,613 +4,939 +(18 +)% +(27 +)% +Total Diagnostics +145,114 +146,114 +141,500 +(1 +)% +3 +% +Life Science- +Americas +20,651 +22,363 +19,040 +(8 +)% +17 +% +EMEA +19,406 +17,845 +20,005 +9 +% +(11 +)% +ROW +10,911 +8,508 +8,287 +28 +% +3 +% +Total Life Science +50,968 +48,716 +47,332 +5 +% +3 +% +Consolidated +$ +196,082 +$ +194,830 +$ +188,832 +1 +% +3 +% +% of total revenues- +Diagnostics +74 +% +75 +% +75 +% +Life Science +26 +% +25 +% +25 +% +Total +100 +% +100 +% +100 +% +Ex-Americas +26 +% +25 +% +29 +% +- 29 - +Table of Contents +Revenue Overview- By Product Platform/Type +The revenues generated by each of our reportable segments result primarily from the sale of the following segment-specific categories of products: +Diagnostics +1) +Molecular tests that operate on our illumi gene platform +2) +Non-molecular tests on multiple technology platforms +Life Science +1) +Molecular components +2) +Immunoassay components +Revenues for each product platform/type, as well as its relative percentage of segment +revenues, are shown below. +2016 vs. +2015 +2015 vs. +2014 +2016 +2015 +2014 +Inc (Dec) +Inc (Dec) +Diagnostics- +Molecular +$ +38,302 +$ +40,880 +$ +36,981 +(6 +)% +11 +% +Non-molecular +106,812 +105,234 +104,519 +1 +% +1 +% +Total Diagnostics +$ +145,114 +$ +146,114 +$ +141,500 +(1 +)% +3 +% +Life Science- +Molecular components +$ +20,599 +$ +20,601 +$ +20,824 +— +% +(1 +)% +Immunoassay components +30,369 +28,115 +26,508 +8 +% +6 +% +Total Life Science +$ +50,968 +$ +48,716 +$ +47,332 +5 +% +3 +% +% of Diagnostics revenues- +Molecular +26 +% +28 +% +26 +% +Non-molecular +74 +% +72 +% +74 +% +Total Diagnostics +100 +% +100 +% +100 +% +% of Life Science revenues- +Molecular components +40 +% +42 +% +44 +% +Immunoassay components +60 +% +58 +% +56 +% +Total Life Science +100 +% +100 +% +100 +% +Following is a discussion of the revenues generated by each of these product platforms/types: +Diagnostics Products +Molecular Products +During fiscal 2016, revenues from our illumi gene molecular platform of products totaled $38,302, representing a 6% decrease +from fiscal 2015 (also 6% in constant-currency). This decrease reflects the ongoing intense competition within the molecular-based testing market. +- 30 - +Table of Contents +We have over 1,500 customer account placements. Of these account placements, approximately 1,300 accounts +have completed evaluations and validations and are regularly purchasing product, with the balance of our account placements being in some stage of product evaluation and/or validation. Of our account placements, we have nearly 450 accounts that +are regularly purchasing, evaluating and/or validating two or more assays. +We continue to invest in new product development for our molecular testing +platform, and this platform now has the following commercialized tests: +1. +illumi gene C. difficile – commercialized in August 2010 +2. +illumi gene Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene Mycoplasma ( M. pneumoniae; walking pneumonia) – commercialized in June 2013 +5. +illumi gene Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene Chlamydia trachomatis – commercialized outside of U.S. in February 2015 +7. +illumi gene Neisseria gonorrhea – commercialized outside of U.S. in February 2015 +8. +illumi gene HSV 1&2 (Herpes Simplex Virus Type 1 & Type 2) – commercialized in July 2015 +9. +illumi gene Malaria – commercialized outside of U.S. in February 2016 +10. +illumi gene Mycoplasma Direct ( M. pneumoniae; walking pneumonia) – commercialized in June 2016 +We believe that the diagnostic testing market is continuing to selectively move away from culture and immunoassay testing to molecular testing for diseases +where there is a favorable cost/benefit position for the total cost of health care. While this market is competitive, with molecular companies such as Cepheid and Becton Dickinson, and others such as Quidel, Great Basin, Nanosphere and Alere, +we believe we are well-positioned to capitalize on the migration to molecular testing. Our simple, easy-to-use, illumi gene platform, with its expanding menu, requires no expensive equipment purchase and little to no maintenance +cost. We believe these features, along with its small footprint and the performance of the illumi gene assays, make illumi gene an attractive molecular platform to any size hospital or physician office +laboratory that runs moderately-complex tests. +Non-molecular Products +Revenues from our Diagnostics segment’s non-molecular products increased 1% in fiscal 2016, also following a 1% increase in fiscal 2015. These +current year results reflect the addition of Magellan’s revenue, increased revenues in our H. pylori immunoassay products, and an overall decrease in revenues of our other immunoassay product lines, most notably our foodborne and certain +other legacy product families. +Since the March 24, 2016 acquisition, revenues from Magellan’s sale of products to test for elevated levels of lead +in blood have totaled $10,034. This level of revenues reflects an 11% increase over the six-month period ended September 30, 2015, which was prior to Meridian ownership. +- 31 - +Table of Contents +During fiscal 2016, revenues from our H. pylori products increased 8% (9% in constant-currency) to +$32,300, which followed a 6% increase during fiscal 2015. This increase continues to reflect the benefits of our partnerships with managed care companies in promoting (i) the health and economic benefits of a test and treat strategy; (ii) +changes in policies that discourage the use of traditional serology methods and promote the utilization of active infection testing methods; and (iii) physician behavior movement away from serology-based testing and toward direct antigen +testing. A significant amount of the H. pylori product revenues are from reference labs, whose buying patterns may not be consistent period to period. In addition to our managed care strategy, we have also employed bulk-buy sales +promotions into selected distribution and laboratory channels as a defensive strategy against potential new competitive product introductions expected in fiscal 2017. +The patents for our H. pylori products are owned by us and expired in May 2016 in the U.S., and will expire in fiscal 2017 in countries outside the +U.S. We expect competition with respect to our H. pylori products to increase in fiscal 2017 as we currently market the only FDA-cleared tests to detect H. pylori antigen in stool samples. Such competition may have an adverse +impact on our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to +mitigate competition, our product development pipeline includes multiple new product initiatives for the detection of H. pylori . We are unable to provide assurances that we will be successful with any mitigation strategy or that any +mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and gross profit. +During fiscal +2016, revenues from our other immunoassay products (including C. difficile , foodborne and respiratory) decreased 16% (15% in constant-currency) to $63,000, following a 2% decrease in fiscal 2015. This decrease results primarily from the +effects of continued increased competition, distributor order patterns and the timing of our promotional “stock-and-block” programs in previous periods. +Life Science Products +During fiscal 2016, revenues from +our Life Science segment increased 5%, with revenues from molecular components sales remaining flat compared to fiscal 2015 and revenues from immunoassay components sales increasing 8%. Life Science segment revenues increased 3% in fiscal 2015, +with revenues from molecular component sales decreasing 1% from fiscal 2014 and revenues from immunoassay component sales increasing 6%. Our molecular components business’ growth was negatively impacted by the movement in currency exchange +rates since fiscal 2015, with revenues increasing 4% on a constant-currency basis over fiscal 2015. Our Life Science segment continued to benefit from increased sales into China, with such sales totaling approximately $4,100 during fiscal 2016 +(approximately $1,000 in the molecular components business and $3,100 in the immunoassay components business). +- 32 - +Table of Contents +Foreign Currency +During fiscal 2016, currency exchange had an approximate $1,700 unfavorable impact on revenues; $700 within the Diagnostics segment and $1,000 within the Life +Science segment. This compares to currency exchange rates having an approximate $4,700 unfavorable impact on revenues in fiscal 2015; $3,200 within the Diagnostics segment and $1,500 within the Life Science segment. Due to natural hedge +relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net earnings was not significant during fiscal 2016, 2015 or 2014. +Significant Customers +Revenue concentrations +related to certain customers within our Diagnostics and Life Science segments are set forth in Note 8 of the accompanying Consolidated Financial Statements. +Medical Device Tax +On January 1, 2013, the +medical device tax established as part of the U.S. health care reform legislation became effective, and as a result, the Company made its first required tax deposit near the end of January 2013. During fiscal 2016, 2015 and 2014, the Company +recorded approximately $500, $1,900 and $1,750, respectively, of medical device tax expense, which is reflected as a component of cost of sales in the accompanying Consolidated Statements of Operations. During December 2015, the Consolidations +Appropriations Act of 2016 imposed a two-year moratorium on this excise tax effective January 1, 2016. During calendar years 2016 and 2017, this moratorium would result in approximately $2,000 of savings each year. We are unable to predict +any future legislative changes or developments related to this moratorium or excise tax. +Gross Profit: +2016 +2015 +2014 +2016 vs. +2015 +Inc (Dec) +2015 vs. +2014 +Inc (Dec) +Gross Profit +$ +127,787 +$ +121,882 +$ +117,243 +5 +% +4 +% +Gross Profit Margin +65 +% +63 +% +62 +% +2 points +1 point +The overall gross profit margin increase during fiscal 2016 primarily results from the combined effects of (i) mix of products +sold, particularly the higher revenue contribution from H. pylori products; (ii) realization of manufacturing facility efficiencies for our illumi gene products as a result of bringing in-house certain reagent dispensing +operations that were previously outsourced; (iii) manufacturing efficiencies in our Life Science segment; (iv) favorable effects of currency rates related to products where the purchase cost is denominated in Euros but the customer sales are billed +in U.S. dollars; and (v) decreased medical device tax payments. The overall increase in the gross profit margin from fiscal 2014 to fiscal 2015 reflects the combined effects of (i) mix of products sold; (ii) realization of manufacturing +facility efficiencies; and (iii) favorable effects of currency rates related to products where the purchase cost is denominated in Euros but the customer sales are billed in U.S. dollars. +- 33 - +Table of Contents +Our overall operations consist of the sale of diagnostic test kits for various disease states and in alternative +test formats, as well as bioresearch reagents, bulk antigens and antibodies, PCR/qPCR reagents, nucleotides, competent cells, and proficiency panels. Product revenue mix shifts, in the normal course of business, can cause the consolidated gross +profit margin to fluctuate by several points. +Operating Expenses: +Research & +Development +Selling & +Marketing +General & +Administrative +Other +Total Operating +Expenses +2014 Expenses +$ +12,552 +$ +24,910 +$ +27,389 +$ +— +$ +64,851 +% of Revenues +7 +% +13 +% +15 +% +— +% +34 +% +Fiscal 2015 Increases (Decreases): +Diagnostics +(306 +) +730 +803 +— +1,227 +Life Science +359 +(39 +) +(576 +) +— +(256 +) +2015 Expenses +$ +12,605 +$ +25,601 +$ +27,616 +$ +— +$ +65,822 +% of Revenues +6 +% +13 +% +14 +% +— +34 +% +% Increase (Decrease) +— +% +3 +% +1 +% +— +% +1 +% +Fiscal 2016 Increases (Decreases): +Diagnostics +1,505 +3,257 +3,051 +2,158 +9,971 +Life Science +(295 +) +1,013 +(102 +) +— +616 +2016 Expenses +$ +13,815 +$ +29,871 +$ +30,565 +$ +2,158 +$ +76,409 +% of Revenues +7 +% +15 +% +16 +% +1 +% +39 +% +% Increase +10 +% +17 +% +11 +% +NMF +16 +% +Total operating expenses increased during both fiscal 2016 and fiscal 2015, resulting primarily from the combined effects of +the following: +Diagnostics +Fiscal 2016 increase +• +Addition of Magellan’s operating expenses since the March 24, 2016 date of acquisition, which represent approximately 50% of the total Diagnostics operating expense increase; +• +Increased investment in Sales & Marketing activities, including new leadership and an expansion in sales territories; +• +Costs incurred in connections with acquisition activities, most notably related to the acquisition of Magellan; and +• +Costs incurred in connection with restructuring Sales & Marketing leadership, which relate to severance obligations for former employees. +- 34 - +Table of Contents +Fiscal 2015 increase +• +Increased personnel costs resulting from increased Sales & Marketing headcount, and increased sales commission payments made in connection with increased sales levels; +• +Increased legal spending over the prior year, largely related to a foreign distributor matter; and +• +Decreased various personnel related costs resulting in part from the death of our Executive Chairman during the fourth quarter of fiscal 2014. +Life Science +Fiscal 2016 +increase +• +Increased investment in Sales & Marketing activities, including increased personnel, travel and marketing spending. +The amount of stock-based compensation expense reported for fiscal 2016, 2015 and 2014 was $2,911, $3,324 and $3,557, respectively. During fiscal 2014 +through fiscal 2016, we granted restricted share units to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining +half being subject to attainment of a specified earnings target for each respective fiscal year. Although dividend equivalents were paid on these units throughout each of the respective fiscal years, because Meridian’s net earnings did not +reach the minimum levels in any of these three fiscal years, the performance-based awards were not earned and no stock-based compensation was recorded for the performance-based awards, except for those performance-based restricted share units being +held by our Executive Chairman at the time of his death in the fourth quarter of fiscal 2014. +Additionally, during both fiscal 2015 and fiscal 2016, in +connection with the extension of an Amended and Restated Employment Agreement, we granted to our Chairman and Chief Executive Officer (i) restricted share units to be earned only if specified revenue and earnings per share targets were achieved for +each of fiscal 2015 and fiscal 2016; and (ii) time-vested options, with half vesting September 30, 2015 and half vesting September 30, 2016. As a result of the fiscal 2015 performance targets being achieved, the restricted share units were +earned and the related compensation expense recorded in fiscal 2015. However, as a result of the fiscal 2016 performance targets not being achieved, the restricted share units have been cancelled and no related compensation expense was recorded +in fiscal 2016. +Operating Income +Operating income +decreased 8% and increased 7% in fiscal 2016 and 2015, respectively, as a result of the factors discussed above. +- 35 - +Table of Contents +Other Income and Expense +Fiscal 2016 other income and expense includes interest costs on a term loan used to fund the acquisition of Magellan. The effective interest rate on this +term loan is 2.76%. In fiscal 2015, other income and expense included $1,100 of foreign currency losses, which related primarily to a foreign subsidiary intercompany loan. This compares to $600 of foreign currency gains and $300 of foreign +currency losses in fiscal 2016 and fiscal 2014, respectively. +Income Taxes +The effective rate for income taxes was 36%, 35% and 33% for fiscal 2016, 2015 and 2014, respectively. The increases over the last two fiscal years result +from (i) the non-deductibility of certain expenses incurred in connection with the Company’s acquisition activities (2016); (ii) increased apportionments in certain state taxing jurisdictions (2016 and 2015); and (iii) the timing of +renewal/expiration of the research and experimentation credit in the U.S. during these periods. +Impact of Inflation +To the extent feasible, we have consistently followed the practice of adjusting our prices to reflect the impact of inflation on salaries and fringe benefits +for employees and the cost of purchased materials and services. Inflation and changing prices did not have a material adverse impact on our gross margin, revenues or operating income in fiscal 2016, 2015 or 2014. +Liquidity and Capital Resources: +Liquidity +Our cash flow and financing requirements are determined by analyses of operating and capital spending budgets, debt service, consideration of +acquisition plans and consideration of common share dividends. We have historically maintained a credit facility to augment working capital requirements and to respond quickly to acquisition opportunities. +We have an investment policy that guides the holdings of our investment portfolio, which presently consists of overnight repurchase agreements, bank savings +accounts and institutional money market mutual funds. Our objectives in managing the investment portfolio are to (i) preserve capital; (ii) provide sufficient liquidity to meet working capital requirements and fund strategic objectives such as +acquisitions; and (iii) capture a market rate of return commensurate with market conditions and our policy’s investment eligibility criteria. As we look forward, we will continue to manage the holdings of our investment portfolio with +preservation of capital being the primary objective. +- 36 - +Table of Contents +On June 23, 2016, the United Kingdom voted to leave the European Union (commonly referred to as +“Brexit”) and while the impact of Brexit remains uncertain, the resulting immediate changes in foreign currency exchange rates has limited overall impact due to natural hedging. However, any predicted deterioration in the United Kingdom +and European economic outlook may have an adverse effect on revenue growth, but the extent of such effect cannot yet be quantified. In the longer term, it is possible that we will be directly impacted in a number of key areas including the hiring +and retention of qualified staff, regulatory affairs, manufacturing and logistics. We are closely monitoring the Brexit developments in order to determine, quantify and proactively address changes as they become clear. Despite the Brexit +developments, we do not expect macroeconomic conditions to have a significant impact on our liquidity needs, financial condition or results of operations, although no assurances can be made in this regard. We intend to continue to fund our +working capital requirements and dividends from current cash flows from operating activities and cash on hand. If needed, we also have an additional source of liquidity through our $30,000 bank revolving credit facility. Our liquidity +needs may change if overall economic conditions worsen and/or liquidity and credit within the financial markets tightens for an extended period of time, and such conditions impact the collectibility of our customer accounts receivable or impact +credit terms with our vendors, or disrupt the supply of raw materials and services. +Fluctuations in overall stock market valuations may raise questions +as to the potential impairment of goodwill and other long-lived assets. Our annual goodwill impairment review takes place as of June 30 th each year, and is performed at the reporting unit +level. There have been no impairments from these annual reviews. As of September 30, 2016, our stock price was $19.29 per share, compared to our book value per share of $3.95. This relationship, stock price trading at a 4.9x multiple +of book value, is an indicator that the fluctuation in overall stock market valuations and its impact on our stock price has not been a triggering event for impairment of our goodwill and other long-lived assets. +Net cash provided by operating activities totaled $37,223 during fiscal 2016, a 13% decrease from the $42,809 provided during fiscal 2015. While +reflecting the effects of the timing of payments from customers, and to suppliers and taxing authorities, this decrease also results in large part from the increase in inventory levels. The levels of inventory in our Life Science segment have +been increased in anticipation of demand related to various initiatives, most notably further expansion into the Asian market. Net cash flows from operating activities and cash on hand are anticipated to be adequate to fund working capital +requirements, capital expenditures and dividends during the next 12 months. +During fiscal 2016, the per share amount of our cash dividends paid +represented 105% of our diluted earnings per share (approximately 100% excluding the effect of costs related to acquisition activities and restructuring our Sales and Marketing leadership), exceeding our long-standing policy of establishing a cash +dividend payout ratio of between 75% and 85% of diluted earnings per share. Despite there being certain individual fiscal years in which our payout ratio has fallen outside of this policy range, since adopting this policy in November 2002, our +cumulative cash dividend payout has only slightly exceeded this range, approximating 86% of cumulative net earnings during this timeframe. +- 37 - +Table of Contents +Capital Resources +In connection with the acquisition of Magellan, the Company entered into a $60,000 five-year term loan with a commercial bank. The term loan requires +quarterly principal and interest payments, with interest at a variable rate tied to LIBOR, and a balloon principal payment at the end of five years (see “Known Contractual Obligations” below). In addition, we have a $30,000 revolving +credit facility with a commercial bank that expires March 31, 2021. As of November 22, 2016, there were no borrowings outstanding on this facility and we had 100% borrowing capacity available to us. We have had no borrowings outstanding +under this revolving credit facility during fiscal 2016, 2015 or 2014. +Our capital expenditures are estimated to range between approximately $3,000 to +$4,000 for fiscal 2017, with the actual amount dependent upon actual operating results and the phasing of certain projects. Such expenditures may be funded with cash and equivalents on hand, operating cash flows and/or availability under the +$30,000 revolving credit facility discussed above. +Known Contractual Obligations: +Known contractual obligations and their related due dates were as follows as of September 30, 2016: +Total +Less than 1 +Year +1-3 Years +4-5 Years +More than +5 Years +Operating leases (1) +$ +4,454 +$ +1,969 +$ +2,297 +$ +188 +$ +— +Purchase obligations (2) +13,653 +11,970 +1,683 +— +— +Term loan principal payments (3) +58,500 +3,750 +15,750 +39,000 +— +Scheduled interest payments (3) +6,186 +1,605 +4,046 +535 +— +Uncertain income tax positions liability and interest +(4) +632 +632 +— +— +— +Total +$ +83,425 +$ +19,926 +$ +23,776 +$ +39,723 +$ +— +(1) +Meridian and its subsidiaries are lessees of (i) office and warehouse buildings in Ohio, Massachusetts, Florida, Australia, Belgium, France, Germany, Singapore, China and the U.K.; (ii) automobiles for use by the +diagnostic direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile machines and copier machines across all business units, under operating lease agreements that expire at various dates. +(2) +Purchase obligations relate primarily to outstanding purchase orders for inventory and service items. These contractual commitments are not in excess of expected production requirements over the next twelve months. +- 38 - +Table of Contents +(3) +These principal and interest payments relate to the $60,000 five-year term loan with a commercial bank entered into in connection with the acquisition of Magellan. The term loan requires quarterly principal and +interest payments, with interest at a variable rate tied to LIBOR, and a balloon principal payment at the end of five years. The interest payments reflect the impact of an interest rate swap agreement with the commercial bank, which effectively +converts the variable interest rate on the term loan to a fixed rate of 2.76%. +(4) +As of September 30, 2016, our liabilities for uncertain tax positions and related interest and penalties were $502 and $130, respectively. Due to inherent uncertainties in the timing of settlement of tax positions, +we are unable to estimate the timing of the effective settlement of these obligations. +Other Commitments and Off-Balance Sheet +Arrangements: +License Agreements +Meridian has entered into various license agreements that require payment of royalties based on a specified percentage of sales of related +products. Approximately 85% of our royalty expenses relate to our Diagnostics operating segment, where the royalty rates range from 4% to 8%. Meridian expects that payments under these agreements will amount to approximately $3,500 in +fiscal 2017. +Off-Balance Sheet Arrangements +We do not utilize any special-purpose financing vehicles or have any undisclosed off-balance sheet arrangements. +Market Risk Exposure: +Foreign Currency Risk +We have market risk exposure related to foreign currency transactions from our operations outside the United States, as well as certain suppliers +to our domestic businesses located outside the United States. The foreign currencies where we have market risk exposure are the Australian dollar, the British pound, the Euro and the Singapore dollar. Assessing foreign currency exposures +is a component of our overall ongoing risk management process, with such currency risks managed as we deem appropriate. +Concentration of +Customers/Products Risk +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 27% of the segment’s total +revenues or 20% of consolidated revenues for fiscal 2016. Additionally, five of our product families accounted for 73% of our Diagnostics segment’s third-party revenues during fiscal 2016, and 54% of our fiscal 2016 consolidated revenues. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two diagnostics manufacturing customers were 18% of the +segment’s total revenues for fiscal 2016, and 5% of our fiscal 2016 consolidated revenues. +- 39 - +Table of Contents +Critical Accounting Policies : +The consolidated financial statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally +accepted in the United States. Such accounting principles require management to make judgments about estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Management +believes that the following accounting policies are critical to understanding the accompanying consolidated financial statements because the application of such polices requires the use of significant estimates and assumptions, and the carrying +values of related assets and liabilities are material. +Revenue Recognition +Our revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue for the Diagnostics segment is +reduced at the date of sale for product price adjustments due to certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, +historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. +Revenue for our +Diagnostics segment includes revenue for our illumi gene molecular test system. This system includes an instrument, instrument accessories and test kits. In markets where the test system is sold via multiple deliverable +arrangements, the cost of the instrument and instrument accessories is deferred upon placement at a customer and amortized on a straight-line basis into cost of sales over the expected utilization period, generally three years. +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The significant deliverables are an instrument, instrument +accessories (e.g., printer) and test kits. An instrument and instrument accessories are delivered to the customer prior to the start of the customer utilization period, in order to accommodate customer set-up and installation. There is de +minimis consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are not a separate unit of accounting because such equipment can only be used to process and +read the results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test result), and therefore the instrument and instrument accessories do not have standalone +value to the customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the customer over the utilization period of the instrument, which we estimate has a useful +life of three years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue for the sale of test kits is recognized upon shipment and transfer of title +to the customers. +In markets where the test system is not sold via multiple deliverable arrangements, the cost of the instrument and instrument +accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of instruments and instrument accessories and test kits is recognized upon shipment and transfer of title to the +customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory the instruments, instrument accessories and test kits for resale to end-users. +- 40 - +Table of Contents +Our products are generally not subject to a customer right of return except for product recall events under the +rules and regulations of the Food and Drug Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a loss was probable and estimable. +Inventories +Our inventories are carried at the +lower of cost or market. Cost is determined on a first-in, first-out (FIFO) basis. We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and other +identified exposures. We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and market conditions were to be less favorable than such estimates, additional inventory write-downs would +be required and recorded in the period known. Such adjustments would negatively affect gross profit margin and overall results of operations. +Intangible Assets +Our intangible assets include +identifiable intangibles and goodwill. Identifiable intangibles include customer lists and relationships, supply agreements, manufacturing technologies, patents, licenses, trade names, and non-compete agreements. All of Meridian’s +identifiable intangibles have finite lives. +Goodwill is subject to an annual impairment review (or more frequently if impairment indicators +arise). There have been no impairments from these analyses. +Identifiable intangibles with finite lives are reviewed for impairment when events or +circumstances indicate that such assets may not be recoverable at their current carrying value. Whether an event or circumstance triggers impairment is determined by comparing an estimate of the asset’s undiscounted future cash flows to +its carrying value. If impairment has occurred, it is measured by a fair-value based test. There were no events or circumstances in fiscal 2016, 2015 or 2014 indicating that the carrying value of such assets may not be recoverable. +Our ability to recover intangible assets, both identifiable intangibles and goodwill, is dependent upon the future cash flows of the related acquired +businesses and assets. We are required to make judgments and assumptions regarding future cash flows, including sales levels, gross profit margins, operating expense levels, working capital levels, and capital expenditures. With respect to +identifiable intangibles, we also make judgments and assumptions regarding useful lives. +- 41 - +Table of Contents +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant +under-performance relative to historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; +and (v) other factors. +If actual cash flows decrease, this could trigger impairment of intangible assets and other long-lived assets. If impairment +were to occur, this would negatively affect overall results of operations. +Income Taxes +Our provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences +between income for financial reporting purposes and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for tax purposes. These differences are +adjusted to actual upon filing of our tax returns, typically occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +Our deferred tax assets include net operating loss carryforwards. The realization of tax benefits related to net operating loss carryforwards is +dependent upon the generation of future taxable income in the applicable jurisdictions. We assess the level of deferred tax asset valuation allowance needed, if any, by taking into consideration historical and future projected operating +results, future reversals of taxable temporary differences, and tax planning strategies. The amount of net deferred tax assets considered realizable could be reduced in future years if estimates of future taxable income during the carryforward +period are reduced. +Undistributed earnings in our non-U.S. subsidiaries are considered by us to be permanently re-invested in such subsidiaries. +Consequently, U.S. deferred tax liabilities on such earnings have not been recorded. +From time to time, our tax returns in federal, state and foreign +jurisdictions are examined by the applicable tax authorities. To the extent that adjustments result from the completion of these examinations or the lapsing of statutes of limitation, they will affect tax liabilities in the period +known. We believe that the results of any tax authority examinations would not have a significant adverse impact on our financial condition or results of operations. +Recent Accounting Pronouncements : +In May 2014, +the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which supersedes and replaces nearly all currently-existing U.S. GAAP revenue recognition guidance including related disclosure requirements. This guidance, +including any clarification guidance thereon, will be effective for the Company beginning October 1, 2018 (fiscal 2019). The Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial +statements. +- 42 - +Table of Contents +In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which +simplifies the financial statement presentation of deferred income taxes by requiring that deferred income tax assets and liabilities be classified as noncurrent within a classified statement of financial position. Adoption and implementation +of the guidance is not required by the Company until issuance of fiscal 2018 first quarter financial statements. However, due to early adoption being permitted and believing the required presentation results in more useful and comparable +information related to our net deferred income taxes, the Company has chosen to adopt the guidance during fiscal 2016 and retrospectively apply the guidance to the prior period presented. This retrospective application results in $3,431 of +deferred income tax assets being reclassified from current assets to non-current assets in the September 30, 2015 balance sheet included herein. Adoption of this guidance did not have an impact on the Company’s consolidated results of +operations or cash flows. +In February 2016, the FASB issued ASU 2016-02, Leases , which amends the accounting guidance related to +leases. These changes, which are designed to increase transparency and comparability among organizations for both lessees and lessors, include, among other things, requiring recognition of lease assets and liabilities on the balance sheet and +disclosing key information about leasing arrangements. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2020, although early adoption is permitted. The Company has not yet completed +its assessment of the impact that adoption of this guidance will have on its financial statements. +In March 2016, the FASB issued ASU 2016-09, +Improvements to Employee Share-Based Payment Accounting , which amends the accounting for share-based payment transactions. These changes, which are designed for simplification, involve several aspects of the accounting for share-based +transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Adoption and implementation of the guidance is not required by the Company until +the beginning of fiscal 2018, although early adoption is permitted. The Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial statements. +In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments . The update addresses certain specific cash +flows and their treatment, with the objective being to reduce the existing diversity in how the items are presented and classified within the statement of cash flows. Adoption and implementation of the guidance is not required by the Company +until the beginning of fiscal 2019, although early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on the Company’s statement of cash flows. +- 43 - +Table of Contents +In October 2016, the FASB issued ASU 2016-16, Intra-Entity Transfers of Assets Other Than Inventory , which +intends to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2019, although +early adoption is permitted. While the Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial statements, in light of the levels of such transfer activity within the Company, +adoption of this guidance is not expected to have a significant impact on the Company’s consolidated results of operations, cash flows or financial position. +ITEM 7A. +QUANTITATIVE AND +QUALITATIVE DISCLOSURES ABOUT MARKET RIS K +See Market Risk Exposure and Capital Resources under Item 7 above beginning on +page 27. +- 44 - +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements +Management’s Report on Internal Control over Financial +Reporting +46 +Reports of Independent Registered Public Accounting Firm +47 +Consolidated Statements of Operations for the years ended September 30, 2016, +2015 and 2014 +50 +Consolidated Statements of Comprehensive Income for the years ended September +30, 2016, 2015 and 2014 +51 +Consolidated Balance Sheets as of September 30, 2016 and 2015 +52 +Consolidated Statements of Shareholders’ Equity for the years ended September +30, 2016, 2015 and 2014 +54 +Consolidated Statements of Cash Flows for the years ended September 30, 2016, +2015 and 2014 +55 +Notes to Consolidated Financial Statements +56 +Schedule No. II – Valuation and Qualifying Accounts for the years ended September +30, 2016, 2015 and 2014 +83 +All other supplemental schedules are omitted due to the absence of conditions under which they are required or because the +information is shown in the Consolidated Financial Statements or Notes thereto. +- 45 - +Table of Contents +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule +13a-15(f). +The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of +records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial +statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable +assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures +may deteriorate. +Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial +Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of September 30, 2016, based on the framework and criteria in the 2013 Internal Control – Integrated Framework, issued by the +Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s evaluation and those criteria, the Company concluded that its system of internal control over financial reporting was effective as of September +30, 2016. The Company’s assessment of and conclusion on the effectiveness of its internal control over financial reporting did not include the internal controls of Magellan Biosciences, Inc., which was acquired during fiscal 2016 and the +results of which since the date of acquisition were included in the 2016 consolidated financial statements. Magellan constituted $78,977 or 31.4% of the Company’s total assets as of September 30, 2016, and $10,034 or 5.1% of total net revenues, +for the year end September 30, 2016. +The Company’s independent registered public accounting firm has issued an attestation report on the +registrant’s internal control over financial reporting. +/s/ John A. Kraeutler +/s/ Melissa A. Lueke +John A. Kraeutler +Melissa A. Lueke +Chief Executive Officer +Executive Vice President and +November 29, 2016 +Chief Financial Officer +November 29, 2016 +- 46 - +Table of Contents +REPORT OF INDE PENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +We have audited the accompanying consolidated balance sheets of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the “Company”) +as of September 30, 2016 and 2015, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2016. Our audits of the basic +consolidated financial statements included the financial statement schedule listed in the index appearing under Schedule No. II. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our +responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. +We conducted our audits in +accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as +well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, +the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Meridian Bioscience, Inc. and subsidiaries as of September 30, 2016 and 2015, and the results of their operations and their +cash flows for each of the three years in the period ended September 30, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered +in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +As discussed in Note 1 to the consolidated financial statements, the Company adopted new accounting guidance during the year ended September 30, 2016 +related to the presentation of deferred income taxes. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight +Board (United States), the Company’s internal control over financial reporting as of September 30, 2016, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated November 29, 2016 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Cincinnati, Ohio +November 29, 2016 +- 47 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +We have audited the internal control over financial reporting of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the +“Company”) as of September 30, 2016, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s +management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal +Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. Our audit of, and opinion on, the Company’s +internal control over financial reporting does not include the internal control over financial reporting of Magellan Biosciences, Inc. (“Magellan”), a wholly-owned subsidiary, whose financial statements reflect total assets and revenues +constituting 31.4 and 5.1 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended September 30, 2016. As indicated in Management’s Report, Magellan was acquired during fiscal year 2016. +Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Magellan. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan +and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial +reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the +circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made +only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could +have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or +detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or +procedures may deteriorate. +- 48 - +Table of Contents +In our opinion, the Company maintained, in all material respects, effective internal control over financial +reporting as of September 30, 2016, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. +We also +have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended September 30, 2016, and our report dated November 29, +2016 expressed an unqualified opinion on those financial statements. +/s/ GRANT THORNTON LLP +Cincinnati, Ohio +November 29, 2016 +- 49 - +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2016 +2015 +2014 +Net Revenues +$ +196,082 +$ +194,830 +$ +188,832 +Cost of Sales +68,295 +72,948 +71,589 +Gross Profit +127,787 +121,882 +117,243 +Operating Expenses: +Research and development +13,815 +12,605 +12,552 +Selling and marketing +29,871 +25,601 +24,910 +General and administrative +30,565 +27,616 +27,389 +Acquisition-related costs +1,481 +— +— +Sales and marketing leadership reorganization costs +677 +— +— +Total operating expenses +76,409 +65,822 +64,851 +Operating Income +51,378 +56,060 +52,392 +Other Income (Expense): +Interest income +67 +23 +25 +Interest expense +(897 +) +— +— +Other, net +96 +(1,020 +) +(309 +) +Total other income (expense) +(734 +) +(997 +) +(284 +) +Earnings Before Income Taxes +50,644 +55,063 +52,108 +Income Tax Provision +18,415 +19,523 +17,365 +Net Earnings +$ +32,229 +$ +35,540 +$ +34,743 +Earnings Per Share Data: +Basic earnings per common share +$ +0.77 +$ +0.85 +$ +0.84 +Diluted earnings per common share +$ +0.76 +$ +0.85 +$ +0.83 +Common shares used for basic earnings per common share +42,010 +41,659 +41,455 +Effect of dilutive stock options and restricted shares and units +383 +353 +458 +Common shares used for diluted earnings per common share +42,393 +42,012 +41,913 +Dividends declared per common share +$ +0.80 +$ +0.80 +$ +0.79 +Anti-dilutive Securities: +Common share options and restricted shares and units +462 +551 +272 +The accompanying notes are an integral part of these consolidated financial statements. +- 50 - +Table of Contents +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2016 +2015 +2014 +Net Earnings +$ +32,229 +$ +35,540 +$ +34,743 +Other comprehensive income (loss): +Foreign currency translation adjustment +(2,732 +) +(2,639 +) +(436 +) +Unrealized loss on cash flow hedge +(729 +) +— +— +Income taxes related to items of other comprehensive income +275 +— +— +Other comprehensive income (loss), net of tax +(3,186 +) +(2,639 +) +(436 +) +Comprehensive Income +$ +29,043 +$ +32,901 +$ +34,307 +The accompanying notes are an integral part of these consolidated financial statements. +- 51 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2016 +2015 +Assets +Current Assets: +Cash and equivalents +$ +47,226 +$ +49,973 +Accounts receivable, less allowances of $334 and $248, respectively +27,102 +26,254 +Inventories +45,057 +35,817 +Prepaid expenses and other current assets +7,406 +7,378 +Total current assets +126,791 +119,422 +Property, Plant and Equipment, at Cost: +Land +1,155 +1,068 +Buildings and improvements +31,487 +29,974 +Machinery, equipment and furniture +45,085 +41,541 +Construction in progress +1,947 +1,139 +Subtotal +79,674 +73,722 +Less: accumulated depreciation and amortization +49,224 +46,230 +Net property, plant and equipment +30,450 +27,492 +Other Assets: +Goodwill +61,982 +22,349 +Other intangible assets, net +29,855 +5,931 +Restricted cash +1,000 +1,000 +Deferred instrument costs, net +1,392 +1,750 +Deferred income taxes +— +4,954 +Other assets +353 +384 +Total other assets +94,582 +36,368 +Total assets +$ +251,823 +$ +183,282 +The accompanying notes are an integral part of these consolidated financial statements. +- 52 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2016 +2015 +Liabilities and Shareholders’ Equity +Current Liabilities: +Accounts payable +$ +7,627 +$ +6,646 +Accrued employee compensation costs +7,106 +5,132 +Other accrued expenses +2,606 +2,587 +Current portion of long-term debt +3,750 +— +Income taxes payable +1,482 +886 +Total current liabilities +22,571 +15,251 +Non-Current Liabilities +Acquisition consideration +2,383 +— +Non-current compensation liabilities +2,305 +2,158 +Interest rate swap liability +729 +— +Long-term debt +54,610 +— +Deferred income taxes +2,753 +— +Total non-current liabilities +62,780 +2,158 +Commitments and Contingencies +Shareholders’ Equity: +Preferred stock, no par value; 1,000,000 shares authorized; none issued +— +— +Common shares, no par value; 71,000,000 shares authorized, 42,106,587 and 41,838,399 issued, +respectively +— +— +Additional paid-in capital +122,356 +117,151 +Retained earnings +49,632 +51,052 +Accumulated other comprehensive loss +(5,516 +) +(2,330 +) +Total shareholders’ equity +166,472 +165,873 +Total liabilities and shareholders’ equity +$ +251,823 +$ +183,282 +The accompanying notes are an integral part of these consolidated financial statements. +- 53 - +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (dollars and shares in +thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +Common +Shares +Issued +Additional +Paid-in +Capital +Retained +Earnings +Accum +Other +Comp +Income +(Loss) +Total +Balance at September 30, 2013 +41,518 +$ +107,412 +$ +46,888 +$ +745 +$ +155,045 +Cash dividends paid - $0.79 per share +— +— +(32,762 +) +— +(32,762 +) +Exercise of stock options +78 +882 +— +— +882 +Issuance of restricted shares, net of forfeitures +(1 +) +— +— +— +— +Conversion of restricted stock units +27 +— +— +— +— +Stock compensation expense +— +3,557 +— +— +3,557 +Net earnings +— +— +34,743 +— +34,743 +Foreign currency translation adjustment +— +— +— +(436 +) +(436 +) +Balance at September 30, 2014 +41,622 +111,851 +48,869 +309 +161,029 +Cash dividends paid - $0.80 per share +— +— +(33,357 +) +— +(33,357 +) +Exercise of stock options +187 +1,976 +— +— +1,976 +Conversion of restricted stock units +29 +— +— +— +— +Stock compensation expense +— +3,324 +— +— +3,324 +Net earnings +— +— +35,540 +— +35,540 +Foreign currency translation adjustment +— +— +— +(2,639 +) +(2,639 +) +Balance at September 30, 2015 +41,838 +117,151 +51,052 +(2,330 +) +165,873 +Cash dividends paid - $0.80 per share +— +— +(33,649 +) +— +(33,649 +) +Exercise of stock options +152 +2,294 +— +— +2,294 +Conversion of restricted stock units +117 +— +— +— +— +Stock compensation expense +— +2,911 +— +— +2,911 +Net earnings +— +— +32,229 +— +32,229 +Foreign currency translation adjustment +— +— +— +(2,732 +) +(2,732 +) +Hedging activity, net of tax +— +— +— +(454 +) +(454 +) +Balance at September 30, 2016 +42,107 +$ +122,356 +$ +49,632 +$ +(5,516 +) +$ +166,472 +The accompanying notes are an integral part of these consolidated financial statements. +- 54 - +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2016 +2015 +2014 +Cash Flows From Operating Activities +Net earnings +$ +32,229 +$ +35,540 +$ +34,743 +Non-cash items included in net earnings: +Depreciation of property, plant and equipment +3,937 +3,470 +3,523 +Amortization of intangible assets +2,690 +1,748 +2,039 +Amortization of deferred instrument costs +1,091 +1,391 +1,702 +Stock-based compensation +2,911 +3,324 +3,557 +Deferred income taxes +(233 +) +(122 +) +(140 +) +Losses on long-lived assets +659 +94 +6 +Change in current assets, net of acquisition +(8,115 +) +(6,079 +) +(1,528 +) +Change in current liabilities, net of acquisition +2,237 +3,238 +(5,996 +) +Other, net +(183 +) +205 +356 +Net cash provided by operating activities +37,223 +42,809 +38,262 +Cash Flows From Investing Activities +Purchases of property, plant and equipment +(4,004 +) +(4,613 +) +(5,306 +) +Purchase of equity method investment +(600 +) +— +— +Proceeds from sale of assets +— +1,138 +— +Purchases of intangibles and other assets +— +(151 +) +(1,696 +) +Acquisition of Magellan, net of cash acquired +(62,091 +) +— +— +Net cash used for investing activities +(66,695 +) +(3,626 +) +(7,002 +) +Cash Flows From Financing Activities +Dividends paid +(33,649 +) +(33,357 +) +(32,762 +) +Proceeds from term loan, net of issuance costs +59,860 +— +— +Payments on term loan +(1,500 +) +— +— +Proceeds and tax benefits from exercises of stock options +2,494 +2,614 +1,009 +Net cash provided by (used for) financing activities +27,205 +(30,743 +) +(31,753 +) +Effect of Exchange Rate Changes on Cash and Equivalents +(480 +) +(1,514 +) +(742 +) +Net (Decrease) Increase in Cash and Equivalents +(2,747 +) +6,926 +(1,235 +) +Cash and Equivalents at Beginning of Period +49,973 +43,047 +44,282 +Cash and Equivalents at End of Period +$ +47,226 +$ +49,973 +$ +43,047 +Supplemental Cash Flow Information +Cash paid for interest +$ +879 +$ +— +$ +— +Cash paid for income taxes +$ +17,915 +$ +20,168 +$ +19,952 +The accompanying notes are an integral part of these consolidated financial statements. +- 55 - +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +Meridian Bioscience, Inc. and Subsidiaries +(dollars +and shares in thousands, except per share data) +(1) +Summary of Significant Accounting Policies +(a) +Nature of Business - Meridian is a fully-integrated life science company whose principal businesses are (i) the development, manufacture and distribution of diagnostic test kits primarily for certain +gastrointestinal, viral, respiratory, and parasitic infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch +reagents used by researchers and other diagnostic manufacturers. +(b) +Principles of Consolidation - The consolidated financial statements include the accounts of Meridian Bioscience, Inc. and its subsidiaries. All intercompany accounts and transactions have been eliminated in +consolidation. Unless the context requires otherwise, references to “Meridian,” “we,” “us,” “our” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +(c) +Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of +assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those +estimates. +(d) +Foreign Currency Translation - Assets and liabilities of foreign operations are translated using year-end exchange rates with gains or losses resulting from translation included as a separate component of +accumulated other comprehensive income or loss. Revenues and expenses are translated using exchange rates prevailing during the year. We also recognize foreign currency transaction gains and losses on certain assets and liabilities that +are denominated in the Australian dollar, British pound, Euro and Singapore dollar currencies. These gains and losses are included in other income and expense in the accompanying consolidated statements of operations. Included within other +income and expense in the consolidated statements of operations for the year ending September 30, 2015 is $1,174 in currency losses related to a foreign subsidiary intercompany loan being marked-to-market. +- 56 - +Table of Contents +(e) +Cash, Cash Equivalents and Investments - The primary objectives of our investment activities are to preserve capital and provide sufficient liquidity to meet operating requirements and fund strategic initiatives +such as acquisitions. We maintain a written investment policy that governs the management of our investments in fixed income securities. This policy, among other things, provides that we may purchase only high credit-quality securities +that have short-term ratings of at least A-2, P-2 and F-2, and long-term ratings of at least A, Baa1 and A, by Standard & Poor’s, Moody’s and Fitch, respectively, at the time of purchase. We consider short-term investments with +original maturities of 90 days or less to be cash equivalents, including overnight repurchase agreements and institutional money market funds. At times our investments of cash and equivalents with various high credit quality financial +institutions may be in excess of the Federal Deposit Insurance Corporation (FDIC) insurance limit. +Our investment portfolio +includes the following components: +September 30, 2016 +September 30, 2015 +Cash and +Equivalents +Other +Cash and +Equivalents +Other +Overnight repurchase agreements +$ +9,988 +$ +— +$ +25,436 +$ +— +Institutional money market funds +10,020 +— +— +— +Cash on hand – +Restricted +— +1,000 +— +1,000 +Unrestricted +27,218 +— +24,537 +— +Total +$ +47,226 +$ +1,000 +$ +49,973 +$ +1,000 +(f) +Inventories - Inventories are stated at the lower of cost or market. Cost is determined on a first-in, first-out (FIFO) basis. illumi gene instruments are carried in inventory until +customer placement, at which time they are transferred to deferred illumi gene instrument costs, unless sold outright. +We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and +other identified exposures. Such reserves were $2,680 and $2,456 at September 30, 2016 and 2015, respectively. We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and market +conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. Such adjustments would negatively affect gross profit margin and overall results of operations. +(g) +Property, Plant and Equipment - Property, plant and equipment are stated at cost. Upon retirement or other disposition, the cost and related accumulated depreciation are removed from the accounts and the +resulting gain or loss is reflected in earnings. Maintenance and repairs are expensed as incurred. Depreciation is computed on the straight-line method in amounts sufficient to write-off the cost over the estimated useful lives, generally +as follows: +Buildings and improvements - 18 to 40 years +Machinery, equipment and furniture - 3 to 10 years +Computer equipment and software - 3 to 5 years +- 57 - +Table of Contents +(h) +Intangible Assets - Goodwill is subject to an annual impairment review (or more frequently if impairment indicators arise) at the reporting unit level, which we perform annually as of June 30, the end of our +third fiscal quarter. A reporting unit is generally an operating segment or one level below an operating segment that constitutes a business for which discrete financial information is available and regularly reviewed by segment +management. At September 30, 2016, we had six reporting units, four of which contained goodwill (Americas Diagnostics, Bioline, Life Science-U.S. and Magellan). We review our reporting unit structure each year as part of our annual +goodwill impairment test, or more frequently in the event of changes in our structure. +During fiscal 2016, the annual +impairment review for our Americas Diagnostics reporting unit consisted of a qualitative assessment. A qualitative assessment is first performed to determine whether it was more likely than not that the fair value of the reporting unit is less +than its carrying value using qualitative indicators. In the event that the reporting unit does not pass the qualitative assessment, the reporting unit’s carrying value is compared to its fair value, with fair value of the reporting unit +estimated using market and discounted cash flow approaches. Our Americas Diagnostics reporting unit satisfied the qualitative assessment for fiscal 2016. +For each of our Bioline and Life Science-U.S. reporting units, we performed a quantitative assessment in order to determine if impairment +existed. As part of this assessment, fair value, as determined through a valuation performed by a third party, was calculated via both market (comparable company) and income (discounted cash flows) approaches. Based upon these approaches, +as well as an average of the two, the fair values of each reporting unit exceeded their carrying values; therefore, both the Bioline and Life Science-U.S. reporting units satisfied the quantitative assessment for fiscal 2016. +The goodwill held by our Magellan reporting unit was recorded at estimated fair value as part of the March 24, 2016 acquisition (see Note 2) +and no events have occurred since that date that would indicate the existence of an impairment. +Goodwill is considered impaired if the +carrying value of the reporting unit exceeds its fair value. We have no intangible assets with indefinite lives other than goodwill. There have been no impairments from the analyses performed for fiscal 2016, 2015 or 2014. +During fiscal 2016, goodwill increased $39,633, reflecting $41,358 from the acquisition of Magellan (Diagnostics operating segment; see Note 2) +and a $1,725 decrease from the currency translation adjustment on the goodwill of the Life Science segment’s Bioline Group. The decrease of $844 in fiscal 2015 solely reflects the effect of the Bioline Group and the currency translation +adjustments thereon. +- 58 - +Table of Contents +A summary of Meridian’s acquired intangible assets subject to amortization, as of September +30, 2016 and 2015 is as follows: +2016 +2015 +As of September 30, +Gross +Carrying +Value +Accum. +Amort. +Gross +Carrying +Value +Accum. +Amort. +Manufacturing technologies, core products and cell lines +$ +21,921 +$ +11,540 +$ +11,582 +$ +10,906 +Trade names, licenses and patents +9,037 +3,947 +6,410 +3,296 +Customer lists, customer relationships and supply agreeements +24,385 +10,511 +12,105 +9,964 +Non-compete agreements +680 +170 +— +— +$ +56,023 +$ +26,168 +$ +30,097 +$ +24,166 +The actual aggregate amortization expense for these intangible assets for fiscal 2016, 2015 and 2014 was +$2,690, $1,748 and $2,039, respectively. The estimated aggregate amortization expense for these intangible assets for each of the five succeeding fiscal years is as follows: fiscal 2017 - $3,671, fiscal 2018 - $3,480, fiscal 2019 - $3,269, +fiscal 2020 - $3,107 and fiscal 2021 - $2,510. +Long-lived assets, excluding goodwill, are reviewed for impairment when events or +circumstances indicate that such assets may not be recoverable at their carrying value. Whether an event or circumstance triggers an impairment is determined by comparing an estimate of the asset’s future undiscounted cash flows to its +carrying value. If impairment has occurred, it is measured by a fair-value based calculation. +Our ability to recover the carrying +value of our intangible assets, both identifiable intangibles and goodwill, is dependent upon the future cash flows of the related acquired businesses and assets. We make judgments and assumptions regarding future cash flows, including sales +levels, gross profit margins, operating expense levels, working capital levels, and capital expenditures. With respect to identifiable intangibles and fixed assets, we also make judgments and assumptions regarding useful lives. +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant under-performance relative to +historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; and (v) other factors. +If actual cash flows are less favorable than projections, this could trigger impairment of intangible assets and other long-lived +assets. If impairment were to occur, this would negatively affect overall results of operations. No triggering events have been identified by the Company for fiscal 2016, 2015 or 2014. +- 59 - +Table of Contents +(i) +Revenue Recognition and Accounts Receivable - Revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue for the Diagnostics segment is reduced at the +date of sale for product price adjustments due to certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, historical +statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. Such accruals were $4,178 at September 30, 2016 and $5,581 at September 30, 2015, and have been netted against +accounts receivable. +Revenue for our Diagnostics segment includes revenue for our illumi gene molecular +test system. This system includes an instrument, instrument accessories and test kits. In markets where the test system is sold via multiple deliverable arrangements, the cost of the instrument and instrument accessories is deferred upon +placement at a customer and amortized on a straight-line basis into cost of sales over the expected utilization period, generally three years. +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The significant deliverables are an instrument, +instrument accessories (e.g., printer) and test kits. An instrument and instrument accessories are delivered to the customer prior to the start of the customer utilization period in order to accommodate customer set-up and installation. There is +de minimis consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are not a separate unit of accounting because such equipment can only be used to +process and read the results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test result), and therefore the instrument and instrument accessories do not have +standalone value to the customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the customer over the utilization period of the instrument, which we estimate has +a useful life of three years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue for the sale of test kits is recognized upon shipment and transfer +of title to the customers. +In markets where the test system is not sold via multiple deliverable arrangements, the cost of the instrument +and instrument accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of instruments and instrument accessories and test kits is recognized upon shipment and transfer of +title to the customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory the instruments, instrument accessories and test kits for resale to end-users. +- 60 - +Table of Contents +Our products are generally not subject to a customer right of return except for product recall +events under the rules and regulations of the Food and Drug Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a loss was probable and estimable. +Trade accounts receivable are recorded in the accompanying consolidated balance sheets at invoiced amounts less provisions for distributor +price adjustments under local contracts and doubtful accounts. The allowance for doubtful accounts represents our estimate of probable credit losses and is based on historical write-off experience and known conditions that would likely lead to +non-payment. The allowance for doubtful accounts and related metrics, such as days’ sales outstanding, are reviewed monthly. Accounts with past due balances over 90 days are reviewed individually for collectibility. Customer +invoices are charged off against the allowance when we believe it is probable that the invoices will not be paid. +(j) +Research and Development Costs - Research and development costs are charged to expense as incurred. Research and development costs include, among other things, salaries and wages for research scientists, +materials and supplies used in the development of new products, costs for development of instrumentation equipment, costs for clinical trials, and costs for facilities and equipment. +(k) +Income Taxes - The provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting +and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, +typically occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +We account for uncertain tax positions using a benefit recognition model with a two-step approach: (i) a more-likely-than-not recognition +criterion; and (ii) a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the +benefit will be sustained on its technical merits, no benefit is recorded. We recognize accrued interest related to unrecognized tax benefits as a portion of our income tax provision in the consolidated statements of operations. See Note +5. +(l) +Stock-Based Compensation - We recognize compensation expense for all share-based awards made to employees, based upon the fair value of the share-based award on the date of the grant. See Note 6(b). +- 61 - +Table of Contents +(m) +Comprehensive Income (Loss) - Comprehensive income (loss) represents the net change in shareholders’ equity during a period from sources other than transactions with shareholders. As reflected in the +accompanying consolidated statements of comprehensive income, our comprehensive income is comprised of net earnings, foreign currency translation, unrealized losses on our cash flow hedge, and the income taxes thereon. +(n) +Shipping and Handling Costs - Shipping and handling costs invoiced to customers are included in net revenues. Costs to distribute products to customers, including freight costs, warehousing costs, and other +shipping and handling activities are included in cost of sales. +(o) +Non-Income Government-Assessed Taxes - We classify all non-income, government-assessed taxes (sales, use and value-added) collected from customers and remitted by us to appropriate revenue authorities, on a net +basis (excluded from net revenues) in the accompanying consolidated statements of operations. +(p) +Recent Accounting Pronouncements - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which supersedes and replaces nearly all currently-existing U.S. GAAP revenue +recognition guidance including related disclosure requirements. This guidance, including any clarification guidance thereon, will be effective for the Company beginning October 1, 2018 (fiscal 2019). The Company has not yet completed its +assessment of the impact that adoption of this guidance will have on its financial statements. +In November 2015, the FASB +issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which simplifies the financial statement presentation of deferred income taxes by requiring that deferred income tax assets and liabilities be classified as noncurrent within +a classified statement of financial position. Adoption and implementation of the guidance is not required by the Company until issuance of fiscal 2018 first quarter financial statements. However, due to early adoption being permitted and +believing the required presentation results in more useful and comparable information related to our net deferred income taxes, the Company has chosen to adopt the guidance during fiscal 2016 and retrospectively apply the guidance to the prior +period presented. This retrospective application results in $3,431 of deferred income tax assets being reclassified from current assets to non-current assets in the September 30, 2015 balance sheet included herein. Adoption of this +guidance did not have an impact on the Company’s consolidated results of operations or cash flows. +In February 2016, the FASB issued +ASU 2016-02, Leases , which amends the accounting guidance related to leases. These changes, which are designed to increase transparency and comparability among organizations for both lessees and lessors, include, among other things, +requiring recognition of lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2020, +although early adoption is permitted. The Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial statements. +- 62 - +Table of Contents +In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment +Accounting , which amends the accounting for share-based payment transactions. These changes, which are designed for simplification, involve several aspects of the accounting for share-based transactions, including the income tax +consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2018, although +early adoption is permitted. The Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial statements. +Issued but not yet effective accounting pronouncements are not expected to have a material impact on the Consolidated Financial Statements. +(q) +Reclassifications - Certain reclassifications have been made to the prior fiscal year financial statements to conform to the current year presentation. Such reclassifications had no impact on net earnings or +shareholders’ equity. +(2) +Magellan Acquisition +On March 24, 2016, we acquired all of the +outstanding common stock of Magellan Biosciences, Inc., and its wholly-owned subsidiary Magellan Diagnostics, Inc. (collectively, “Magellan”), for $67,874, utilizing the proceeds from a new $60,000 five-year term loan and cash and +equivalents on hand. An amount of the acquisition consideration totaling $2,383 remains payable to the sellers, pending the realization of tax benefits for certain net operating loss carryforwards in future tax returns. Headquartered near +Boston, Massachusetts, Magellan is a leading manufacturer of FDA-cleared products for the testing of blood to diagnose lead poisoning in children and adults. Magellan is the leading provider of point-of-care lead testing systems in the U.S. +As a result of the consideration paid exceeding the preliminary fair value of the net assets acquired, goodwill in the amount of $41,358 was recorded in +connection with this acquisition, none of which will be deductible for tax purposes. This goodwill results largely from the addition of Magellan’s complementary customer base and distribution channels, industry reputation in the U.S. as a +leader in lead testing, and management talent and workforce. Our fiscal 2016 Consolidated Statement of Operations includes $1,105 of acquisition-related costs related to the Magellan acquisition, which are reflected as Operating Expenses. +- 63 - +Table of Contents +In addition to Magellan’s results of operations, which are included in our fiscal 2016 Consolidated +Statement of Operations and reported as part of the Diagnostics operating segment, the consolidated results for fiscal 2016 also include: +(i) +$181 of cost of sales related to the roll-out of fair value inventory adjustments for sales of products that were in Magellan’s inventory on the date of acquisition and, therefore, were valued at fair value, rather +than manufactured cost, in the opening balance sheet; and +(ii) +$1,337 of general and administrative expenses related to the depreciation of the fair value adjustment to acquired property, plant and equipment, and the amortization of specific identifiable intangible assets recorded +on the opening balance sheet including customer relationships, technology, non-compete agreements, and trade names. +The Company’s +fiscal 2016 consolidated results include net revenues and net earnings of Magellan totaling $10,034 and $848, respectively, reflecting the items noted above but excluding interest expense on the debt secured by Meridian in connection with the +transaction. +The recognized preliminary amounts of identifiable assets acquired and liabilities assumed in the acquisition of Magellan are as follows: +PRELIMINARY +March 24, +2016 +Measurement +March 24, +(as initially +Period +2016 +reported) +Adjustments +(as adjusted) +Fair value of assets acquired - +Cash and equivalents +$ +3,400 +$ +— +$ +3,400 +Accounts receivable +1,700 +— +1,700 +Inventories +1,400 +— +1,400 +Other current assets +300 +— +300 +Property, plant and equipment +2,800 +(200 +) +2,600 +Goodwill +42,800 +(1,400 +) +41,400 +Other intangible assets (estimated useful life): +Customer relationships (15 years) +12,600 +200 +12,800 +Technology (10 years) +10,600 +— +10,600 +Non-compete agreements (2 years) +700 +— +700 +Trade names (approximate 9 year weighted average) +3,700 +(800 +) +2,900 +80,000 +(2,200 +) +77,800 +Fair value of liabilities assumed - +Accounts payable and accrued expenses +1,600 +100 +1,700 +Deferred income tax liabilities +10,600 +(2,400 +) +8,200 +Total consideration paid (including $2,400 accrued to be paid) +$ +67,800 +$ +100 +$ +67,900 +- 64 - +Table of Contents +As indicated, the allocation of the purchase price and estimated useful lives of property, plant and equipment, +and intangible assets shown remain preliminary, pending final completion of valuations. We are currently assessing the amount of tax net operating loss carryforwards available to us. Upon completion of this analysis, an amount will be +reclassified from goodwill to deferred taxes. +The consolidated pro forma results of the combined entities of Meridian and Magellan, had the acquisition +date been October 1, 2014, are as follows for the periods indicated: +(UNAUDITED) +Fiscal Year Ended +September 30, +2016 +2015 +Net Revenues +$ +203,720 +$ +211,250 +Net Earnings +$ +32,675 +$ +34,182 +These pro forma amounts have been calculated by including the results of Magellan, and adjusting the combined results to give +effect to the following, as if the acquisition had been consummated on October 1, 2014, together with the consequential tax effects thereon: +(i) +remove the effect of transaction costs incurred by the Company ($1,105); +(ii) +reflect the additional depreciation and amortization that would have been charged in connection with the preliminary fair value adjustments to inventory, property, plant and equipment, and identifiable intangible assets +($800 and $2,885 in fiscal 2016 and fiscal 2015, repectively); +(iii) +reflect equity-based awards granted under the Company’s 2012 Stock Incentive Plan to certain Magellan employees in accordance with executed employee agreements, and to certain Meridian employees to reward them for +their efforts in connection with the transaction ($250 in fiscal 2015); and +(iv) +reflect the interest expense that would have been incurred on the Company’s $60,000 term note ($690 and $1,685 in fiscal 2016 and fiscal 2015, respectively). +(3) +Inventories +Inventories are comprised of the following: +As of September 30, +2016 +2015 +Raw materials +$ +7,639 +$ +7,095 +Work-in-process +13,146 +10,096 +Finished goods - instruments +2,378 +1,890 +Finished goods - kits and reagents +21,894 +16,736 +Total +$ +45,057 +$ +35,817 +- 65 - +Table of Contents +(4) +Bank Credit Arrangements +In connection with the acquisition of Magellan (see Note 2), on March +22, 2016 the Company entered into a $60,000 five-year term loan with a commercial bank. The term loan requires quarterly principal and interest payments, with interest at a variable rate tied to LIBOR, and a balloon principal payment at the end +of five years. The required principal payments on the term loan for each of the five succeeding fiscal years are as follows: fiscal 2017 - $3,750, fiscal 2018 - $4,500, fiscal 2019 - $5,250, fiscal 2020 - $6,000, and fiscal 2021 - +$39,000. Due to the recent execution date of the term loan and interest being determined on a variable rate basis, the fair value of the term loan at September 30, 2016 approximates the current carrying value reflected in the accompanying +Consolidated Balance Sheet. +In order to limit exposure to volatility in the LIBOR interest rate, the Company and the commercial bank also entered into an +interest rate swap that effectively converts the variable interest rate on the term loan to a fixed rate of 2.76%. With an initial notional balance of $60,000, the interest rate swap has been established with critical terms identical to those +of the term loan, including (i) notional reduction amounts and dates; (ii) LIBOR settlement rates; (iii) rate reset dates; and (iv) term/maturity. Due to this, the interest swap has been designated as an effective cash flow hedge, with changes +in fair value reflected as a separate component of other comprehensive income in the accompanying Consolidated Statements of Comprehensive Income and accumulated other comprehensive loss in the accompanying Consolidated Balance Sheets. At +September 30, 2016, the fair value of the interest rate swap was a liability of $729, and is reflected as a non-current liability in the accompanying Consolidated Balance Sheet. This fair value was determined by reference to a third party +valuation, and is considered a Level 2 input within the fair value hierarchy of valuation techniques. +In addition, the Company continues to maintain a +$30,000 revolving credit facility with a commercial bank, which expires March 31, 2021. As there were no borrowings outstanding on this revolving credit facility at September 30, 2016 or September 30, 2015, available borrowings as of both dates +totaled $30,000. +The term loan and revolving credit facility are collateralized by the business assets of the Company’s U.S. subsidiaries and require +compliance with financial covenants that limit the amount of debt obligations and require a minimum level of coverage of fixed charges, as defined in the borrowing agreement. As of September 30, 2016, the Company is in compliance with all +covenants. The Company is also required to maintain a cash compensating balance with the bank in the amount of $1,000, pursuant to this bank revolving credit facility and is in compliance with this requirement. +- 66 - +Table of Contents +(5) +Income Taxes +(a) +Earnings before income taxes, and the related provision for income taxes for the years ended September 30, 2016, 2015 and 2014 were as follows: +Year Ended September 30, +2016 +2015 +2014 +Domestic +$ +44,795 +$ +50,653 +$ +48,350 +Foreign +5,849 +4,410 +3,758 +Total earnings before income taxes +$ +50,644 +$ +55,063 +$ +52,108 +Provision (credit) for income taxes - +Federal - +Current +$ +16,178 +$ +16,152 +$ +15,021 +Temporary differences +Fixed asset basis differences and depreciation +(45 +) +50 +108 +Intangible asset basis differences and amortization +(744 +) +(421 +) +(210 +) +Currently non-deductible expenses and reserves +(694 +) +217 +50 +Stock-based compensation +129 +126 +59 +Tax credit carryforwards +41 +250 +225 +Other, net +181 +19 +66 +Subtotal +15,046 +16,393 +15,319 +State and local +2,421 +2,236 +1,762 +Foreign +948 +894 +284 +Total income tax provision +$ +18,415 +$ +19,523 +$ +17,365 +(b) +The following is a reconciliation between the statutory U.S. income tax rate and the effective rate derived by dividing the provision for income taxes by earnings before income taxes: +Year Ended September 30, +2016 +2015 +2014 +Computed income taxes at statutory rate +$ +17,719 +35.0 +% +$ +19,264 +35.0 +% +$ +18,238 +35.0 +% +Increase (decrease) in taxes resulting from - +State and local income taxes +1,329 +2.6 +1,365 +2.5 +1,061 +2.0 +Net benefit on foreign dividend +— +— +— +— +(274 +) +(0.5 +) +Foreign tax rate differences +(337 +) +(0.7 +) +(217 +) +(0.4 +) +(430 +) +(0.8 +) +Qualified domestic production incentives +(1,290 +) +(2.5 +) +(1,197 +) +(2.2 +) +(1,175 +) +(2.3 +) +Acquisition-related costs +215 +0.4 +— +— +— +— +Uncertain tax position activity +122 +0.2 +(25 +) +— +164 +0.3 +Valuation allowance +327 +0.7 +7 +— +(288 +) +(0.5 +) +Other, net +330 +0.7 +326 +0.6 +69 +0.1 +$ +18,415 +36.4 +% +$ +19,523 +35.5 +% +$ +17,365 +33.3 +% +- 67 - +Table of Contents +(c) +The components of net deferred tax assets were as follows: +As of September 30, +2016 +2015 +Deferred tax assets - +Valuation reserves and non-deductible expenses +$ +2,366 +$ +1,931 +Stock compensation expense not deductible +3,110 +3,221 +Net operating loss and tax credit carryforwards +2,190 +590 +Basis difference in equity-method investee +302 +— +Inventory basis differences +1,620 +1,186 +Other +297 +8 +Subtotal +9,885 +6,936 +Less valuation allowance +(342 +) +(15 +) +Deferred tax assets +9,543 +6,921 +Deferred tax liabilities - +Fixed asset basis differences and depreciation +(1,526 +) +(995 +) +Intangible asset basis differences and amortization +(10,770 +) +(972 +) +Deferred tax liabilities +(12,296 +) +(1,967 +) +Net deferred tax (liabilities) assets +$ +(2,753 +) +$ +4,954 +For income tax purposes, we have recorded deferred tax assets related to operating loss and tax credit carryforwards in both +U.S. and foreign jurisdictions totaling $1,945 and $245, respectively, as of September 30, 2016. At September 30, 2015, such deferred tax assets totaled $590. The operating loss carryforwards in foreign jurisdictions have no expiration +date. The operating loss carryforwards in the U.S. expire between 2023 and 2036 at the federal level, and between 2028 and 2036 at the state level. The aggregate amount of federal, state and foreign operating loss carryforwards total +$4,956, $3,981 and $836, respectively, at September 30, 2016. The use of the federal and state losses is limited by the change of ownership provisions of the Internal Revenue Code. +The realization of deferred tax assets is dependent upon the generation of future taxable income in the applicable jurisdictions. We have considered the +levels of currently anticipated pre-tax income in U.S. and foreign jurisdictions in assessing the required level of the deferred tax asset valuation allowance including the characterization of the income as ordinary or capital. Taking into +consideration historical and current operating results, and other factors, we believe that it is more likely than not that the net deferred tax asset of $9,543 will be realized. The amount of the net deferred tax asset considered realizable, +however, could be reduced in future years if estimates of future taxable income are reduced. +Undistributed earnings reinvested indefinitely in our +non-U.S. operations were approximately $10,000 at both September 30, 2016 and September 30, 2015. U.S. deferred tax liabilities of approximately $2,000 and $1,800 on such earnings, after consideration of foreign tax credits, have not been +recorded as of September 30, 2016 and September 30, 2015, respectively. +- 68 - +Table of Contents +As described in Note 1, we utilize a comprehensive model for the recognition, measurement, presentation and +disclosure of uncertain tax positions, assuming full knowledge of all relevant facts by the applicable tax authorities. The total amount of unrecognized tax benefits at September 30, 2016 and September 30, 2015 related to such positions was +$502 and $238, respectively, of which the full amounts would favorably affect the effective tax rate if recognized. We recognize interest and penalties related to uncertain tax positions as a component of our income tax provision. During +fiscal 2016, we increased our tax provision by approximately $8 for such penalties and interest, and recorded approximately $85 to the opening balance sheet of Magellan. During fiscal 2015, we decreased our tax provision by approximately $19 +for such penalties and interest. We had approximately $130 accrued for the payment of interest and penalties at September 30, 2016 compared to $37 accrued at September 30, 2015. The amount of our liability for uncertain tax positions +expected to be paid or settled in the next 12 months is uncertain. +A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as +follows: +2016 +2015 +Unrecognized income tax benefits beginning of year +$ +238 +$ +316 +Additions for tax positions of prior years +264 +9 +Reductions for tax positions of prior years +— +(28 +) +Tax examination and other settlements +— +(59 +) +Unrecognized income tax benefits at end of year +$ +502 +$ +238 +We are subject to examination by the tax authorities in the U.S. (both federal and state) and the countries of Australia, +Belgium, China, England, France, Germany, Holland, Italy and Singapore. In the U.S., open tax years are fiscal 2013, fiscal 2014 and fiscal 2015. In countries outside the U.S., open tax years generally range from fiscal 2011 and +forward. However, in Australia, Belgium and Singapore, the utilization of local net operating loss carryforwards extends the statute of limitations for examination well into the foreseeable future. +(6) +Employee Benefits +(a) +Savings and Investment Plan - We have a profit sharing and retirement savings plan covering substantially all full-time U.S. employees. Profit sharing contributions to the plan, which are discretionary, are +approved by the board of directors. The plan permits participants to contribute to the plan through salary reduction. Under terms of the plan, we match 100% of an employee’s contributions, up to a maximum match of 3% of eligible +compensation. Our discretionary and matching contributions to the plan amounted to approximately $1,631, $1,567 and $1,542, during fiscal 2016, 2015 and 2014, respectively. +(b) +Stock-Based Compensation Plans - During fiscal 2016, we had two active stock-based compensation plans, the 2004 Equity Compensation Plan, which became effective December 7, 2004, as amended (the “2004 +Plan”) and the 2012 Stock Incentive Plan, which became effective January 25, 2012 (the “2012 Plan”). +- 69 - +Table of Contents +Each of the 2004 Plan and 2012 Plan authorized the granting of new shares for options, restricted +shares or restricted share units for up to 3,000 shares, with the non-granted portion of the 2004 Plan permitted to be carried forward and added to the 2012 Plan authorized limit. As of September 30, 2016, we have granted 1,492 and 1,241 shares +under the 2004 Plan and 2012 Plan, respectively, thereby resulting in a remaining authorized limit of 3,267 shares. Options may be granted at exercise prices not less than 100% of the closing market value of the underlying common shares on the +date of grant and have maximum terms up to ten years. Vesting schedules for options, restricted shares and restricted share units are established at the time of grant and may be set based on future service periods, achievement of performance +targets or a combination thereof. All options contain provisions restricting their transferability and limiting their exercise in the event of termination of employment or the disability or death of the optionee. We recognize compensation +expense for all share-based payments made to employees, based upon the fair value of the share-based payment on the date of the grant. +During fiscal 2014, we granted approximately 270 restricted share units (with a weighted-average grant date fair value of $24.82 per share) to +certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings +target for fiscal 2014. While dividend equivalents were paid on these units throughout fiscal 2014, the target for fiscal 2014 was not met and, with the exception of these awards being held by our Executive Chairman at the time of his death in +the fourth quarter of fiscal 2014, the performance-based portion of the restricted share units granted during fiscal 2014 were cancelled. +During fiscal 2015, we granted approximately 270 restricted share units (with a weighted-average grant date fair value of $17.91 per share) to +certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings +target for fiscal 2015. While dividend equivalents were paid on these units throughout fiscal 2015, the target for fiscal 2015 was not met and the performance-based portion of these restricted share units granted during fiscal 2015 were +cancelled. +Additionally, during fiscal 2015 in connection with the extension of an Amended and Restated Employment Agreement, we granted to +our Chairman and Chief Executive Officer (i) 25 restricted share units (with a grant date fair value of $16.50 per share) to be earned only if specified revenue and earnings per share targets were achieved for fiscal 2015; and (ii) 100 time-vested +options (with a weighted-average grant date fair value of $3.73 per share, as included in the options table below), with half vesting September 30, 2015 and half vesting September 30, 2016. As a result of the fiscal 2015 performance +targets being achieved, the restricted share units have been earned and the related compensation expense recorded in fiscal 2015. +- 70 - +Table of Contents +Similar to previous years, during fiscal 2016, we granted approximately 370 restricted share +units (with a weighted-average grant date fair value of $19.38 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, +and the remaining half being subject to attainment of a specified earnings target for fiscal 2016. While dividend equivalents were paid on these units throughout fiscal 2016, the target for fiscal 2016 was not met and the performance-based +portion of these restricted share units granted during fiscal 2016 have been cancelled. +Additionally, during fiscal 2016 in connection with +the Amended and Restated Employment Agreement described above, we granted to our Chairman and Chief Executive Officer, 25 restricted share units (with a grant date fair value of $17.03 per share) to be earned only if specified revenue and earnings +per share targets were achieved for fiscal 2016. As a result of the fiscal 2016 performance targets not being achieved, the restricted share units have been cancelled. +Giving effect to these grants, cancellations and certain other activities for restricted shares and restricted share units throughout the +years, including conversions to common shares, forfeitures, and new hire and employee promotion grants, approximately 460 restricted share units remain outstanding as of September 30, 2016, with a weighted-average grant date fair value of $20.17 per +share, a weighted-average remaining vesting period of 1.89 years and an aggregate intrinsic value of $8,867. The weighted-average grant date fair value of the approximate 116 restricted share units that vested during fiscal 2016 was $17.38 per +share. +The amount of stock-based +compensation expense reported was $2,911, $3,324 and $3,557 in fiscal 2016, 2015 and 2014, respectively. The fiscal 2016 expense is comprised of $560 related to stock options and $2,351 related to restricted shares and units; the fiscal 2015 +expense is comprised of $591 related to stock options and $2,733 related to restricted shares and units; and the fiscal 2014 expense is comprised of $486 related to stock options and $3,071 related to restricted shares and units. The total +income tax benefit recognized in the income statement for these stock-based compensation arrangements was $1,100, $1,250 and $1,185, for fiscal 2016, 2015 and 2014, respectively. As of September 30, 2016, we expect future stock compensation +expense for unvested options and unvested restricted stock units to total $376 and $2,232, respectively, which will be recognized during fiscal years 2017 through 2020. +We recognize compensation expense only for the portion of shares that we expect to vest. As such, we apply estimated forfeiture rates to +our compensation expense calculations. These rates have been derived using historical forfeiture data, stratified by several employee groups. During fiscal 2016, 2015 and 2014, we recorded $76, $86 and $108, respectively, in stock +compensation expense to adjust estimated forfeiture rates to actual. +- 71 - +Table of Contents +We have elected to use the Black-Scholes option pricing model to determine grant-date fair value +for stock options, with the following assumptions: (i) expected share price volatility based on the average of Meridian’s historical volatility over the options’ expected lives and implied volatility based on the value of tradable call +options; (ii) expected life of options based on contractual lives, employees’ historical exercise behavior and employees’ historical post-vesting employment termination behavior; (iii) risk-free interest rates based on treasury rates that +correspond to the expected lives of the options; and (iv) dividend yield based on the expected yield on underlying Meridian common stock. +Year ended September 30, +2016 +2015 +2014 +Risk-free interest rates +1.63% +2.07% +1.80% +Dividend yield +4.4% +3.7% +3.5% +Life of option +6.39 yrs. +6.33 yrs. +6.29 yrs. +Share price volatility +31% +33% +33% +Forfeitures (by employee group) +0%-16% +0%-15% +0%-14% +A summary of the status of our stock option plans at September 30, 2016 and changes during the year is +presented in the table and narrative below: +Options +Wtd Avg +Exercise +Price +Wtd Avg +Remaining +Life (Yrs) +Aggregate +Intrinsic +Value +Outstanding beginning of period +816 +$ +20.54 +Grants +239 +19.02 +Exercises +(152 +) +15.64 +Forfeitures +(63 +) +23.64 +Cancellations +(60 +) +17.88 +Outstanding end of period +780 +$ +20.97 +6.05 +$ +604 +Exercisable end of period +583 +$ +21.42 +4.99 +$ +560 +A summary of the status of our nonvested options as of September 30, 2016, and changes during the year ended +September 30, 2016, is presented below: +Options +Weighted- +Average +Grant Date +Fair Value +Nonvested beginning of period +139 +$ +4.18 +Granted +239 +3.46 +Vested +(121 +) +3.91 +Cancelled +(60 +) +3.48 +Nonvested end of period +197 +$ +3.64 +- 72 - +Table of Contents +The weighted average grant-date fair value of options granted was $3.46, $3.95 and $5.48 for +fiscal 2016, 2015 and 2014, respectively. The total intrinsic value of options exercised was $616, $850 and $1,110 for fiscal 2016, 2015 and 2014, respectively. The total grant-date fair value of options that vested during fiscal 2016, +2015 and 2014 was $474, $571 and $701, respectively. +Cash received from options exercised was $2,364, $2,478 and $567 for fiscal 2016, +2015 and 2014, respectively. Tax (expense) benefits recorded to additional paid-in capital from option exercises totaled ($70), ($502) and $315 for fiscal 2016, 2015 and 2014, respectively. +(7) +Non-Current Liabilities +The Company has provided certain post-employment benefits to its +Chairman and Chief Executive Officer and its Chief Commercial Officer. These obligations total $1,628 and $1,399 at September 30, 2016 and 2015, respectively. In addition, we are required by the governments of certain of the foreign +countries in which we operate to maintain a level of reserves for potential future severance indemnity. These reserves total $565 and $668 at September 30, 2016 and 2015, respectively. +(8) +Reportable Segments and Major Concentration Data +Our reportable segments are Diagnostics and +Life Science. The Diagnostics segment consists of manufacturing operations for infectious disease products in Cincinnati, Ohio and, as a result of the acquisition of Magellan, manufacturing operations for products detecting elevated lead levels +in blood in Billerica, Massachusetts (near Boston), and the sale and distribution of diagnostics products domestically and abroad. The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, +England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch reagents domestically and abroad, including sales and business +development offices in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. +Revenues from individual customers +constituting 10% or more of consolidated net revenues are as follows: +Year Ended September 30, +2016 +2015 +2014 +Customer A +$ +20,246 +(10 +)% +$ +29,155 +(15 +)% +$ +28,278 +(15 +)% +Customer B +$ +19,585 +(10 +)% +$ +25,276 +(13 +)% +$ +22,780 +(12 +)% +- 73 - +Table of Contents +Accounts receivable from these two Diagnostics distributor customers accounted for 16% and 21% of consolidated +accounts receivable at September 30, 2016 and September 30, 2015, respectively. The Company’s international revenues totaled $55,291, $52,313 and $57,051 in fiscal years 2016, 2015 and 2014, respectively. Five of our product families +– C. difficile, foodborne, H. pylori , respiratory and women’s health & STD – accounted for 54%, 59% and 58% of consolidated net revenues in fiscal 2016, 2015 and 2014, respectively. We currently purchase on a +sole-source basis from a U.S. and an Italian manufacturer, respectively, the illumi pro -10 instruments on which our illumi gene molecular testing platform operates and the LeadCare instruments used to test for +blood lead levels. Additionally, two of our foodborne products sourced from another vendor accounted for 11%, 14% and 14% of third-party revenues for our Diagnostics segment in fiscal 2016, 2015 and 2014, respectively. +Significant revenue information by country for the Diagnostics and Life Science segments is as follows. Revenues are attributed to the geographic area +based on the location to which the product is delivered. +Year Ended September 30, +2016 +2015 +2014 +United States +$ +120,826 +$ +120,599 +$ +112,917 +Italy +6,599 +7,090 +8,469 +United Kingdom +1,991 +1,964 +1,942 +Japan +1,644 +2,603 +2,097 +France +1,605 +1,603 +1,841 +Belgium +1,501 +1,289 +1,241 +Holland +1,188 +1,326 +1,613 +Canada +1,024 +1,315 +1,359 +Other countries +8,736 +8,325 +10,021 +Total Diagnostics +$ +145,114 +$ +146,114 +$ +141,500 +Year Ended September 30, +2016 +2015 +2014 +United States +$ +19,965 +$ +21,918 +$ +18,864 +Germany +6,982 +5,699 +7,232 +United Kingdom +6,410 +5,782 +5,647 +China +4,080 +2,526 +1,003 +Australia +3,153 +3,590 +4,063 +France +2,167 +2,026 +1,633 +Japan +1,320 +1,158 +1,306 +Other countries +6,891 +6,017 +7,584 +Total Life Science +$ +50,968 +$ +48,716 +$ +47,332 +Identifiable assets for our Italian distribution organization were $8,782 and $8,497 at September 30, 2016 and 2015, +respectively. At September 30, 2016, identifiable assets for the Bioline Group’s operations in the U.K., Germany and Australia totaled approximately $14,973, $7,024 and $3,780, respectively; and totaled approximately $15,647, $6,909 and +$3,891, respectively, at September 30, 2015. +- 74 - +Table of Contents +Segment information for the years ended September 30, 2016, 2015 and 2014 is as +follows: +Diagnostics +Life Science +Elim (1) +Total +Fiscal Year 2016 - +Net revenues – +Third-party +$ +145,114 +$ +50,968 +$ +— +$ +196,082 +Inter-segment +289 +893 +(1,182 +) +— +Operating income +38,202 +12,997 +179 +51,378 +Depreciation and amortization +5,471 +2,247 +— +7,718 +Capital expenditures +2,690 +1,314 +— +4,004 +Goodwill +42,608 +19,374 +— +61,982 +Other intangible assets +27,534 +2,321 +— +29,855 +Total assets +185,241 +66,624 +(42 +) +251,823 +Fiscal Year 2015 - +Net revenues – +Third-party +$ +146,114 +$ +48,716 +$ +— +$ +194,830 +Inter-segment +334 +1,300 +(1,634 +) +— +Operating income +44,136 +12,057 +(133 +) +56,060 +Depreciation and amortization +4,099 +2,510 +— +6,609 +Capital expenditures +3,112 +1,501 +— +4,613 +Goodwill +1,250 +21,099 +— +22,349 +Other intangible assets +2,364 +3,567 +— +5,931 +Total assets +119,939 +63,670 +(327 +) +183,282 +Fiscal Year 2014 - +Net revenues – +Third-party +$ +141,500 +$ +47,332 +$ +— +$ +188,832 +Inter-segment +432 +1,009 +(1,441 +) +— +Operating income +40,740 +11,750 +(98 +) +52,392 +Depreciation and amortization +4,283 +2,981 +— +7,264 +Capital expenditures +4,176 +1,130 +— +5,306 +Goodwill +1,250 +21,943 +— +23,193 +Other intangible assets +2,756 +5,057 +— +7,813 +Total assets +109,350 +67,834 +(255 +) +176,929 +(1) Eliminations +consist of intersegment transactions. +A reconciliation of segment operating expenses to consolidated earnings +before income taxes for the years +ended September 30, 2016, 2015 and 2014 is as follows: +Year Ended September 30, +2016 +2015 +2014 +Segment operating income +$ +51,378 +$ +56,060 +$ +52,392 +Interest income +67 +23 +25 +Interest expense +(897 +) +— +— +Other, net +96 +(1,020 +) +(309 +) +Consolidated earnings before income taxes +$ +50,644 +$ +55,063 +$ +52,108 +Transactions between segments are accounted for at established intercompany prices for internal and management purposes with +all intercompany amounts eliminated in consolidation. +- 75 - +Table of Contents +(9) +Commitments and Contingencies +(a) +Royalty Commitments - We have entered into various license agreements that require payment of royalties based on a specified percentage of the sales of licensed products. Approximately 85% of our royalty +expenses relate to our Diagnostics operating segment, where the royalty rates range from 4% to 8%. These royalty expenses are recognized on an as-earned basis and recorded in the year earned as a component of cost of sales. Annual royalty +expenses associated with these agreements were approximately $3,134, $3,106 and $3,482, respectively, for the fiscal years ended September 30, 2016, 2015 and 2014. +(b) +Purchase Commitments - Excluding the operating lease commitments reflected in Note 9(c) below, we have purchase commitments primarily for inventory and service items as part of the normal course of +business. Commitments made under these obligations are $11,970, $1,620 and $63 for fiscal 2017, 2018 and 2019, respectively. No purchase commitments have been made beyond fiscal 2019. +(c) +Operating Lease Commitments - Meridian and its subsidiaries are lessees of (i) certain office and warehouse buildings in the U.S., Europe, Australia, Singapore and China; (ii) automobiles for use by the direct +sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile and copier machines across all business units, under operating lease agreements that expire at various dates. Amounts charged to expense under operating +leases were $1,966, $1,797 and $1,951 for fiscal 2016, 2015 and 2014, respectively. Operating lease commitments for each of the five succeeding fiscal years are as follows: fiscal 2017 - $1,969, fiscal 2018 - $1,451, fiscal 2019 - $648, fiscal +2020 - $198; and fiscal 2021 - $188. +(d) +Litigation - We are a party to various litigation matters from time to time that we believe are in the normal course of business. The ultimate resolution of these matters is not expected to have a material +adverse effect on our financial position, results of operations or cash flows. +(e) +Indemnifications - In conjunction with certain contracts and agreements, we provide routine indemnifications whose terms range in duration and in some circumstances are not explicitly defined. The maximum +obligation under some such indemnifications is not explicitly stated and, as a result of our having no history of paying such indemnifications, cannot be reasonably estimated. We have not made any payments for these indemnifications and no +liability is recorded at September 30, 2016 or September 30, 2015. We believe that if we were to incur a loss on any of these matters, the loss would not have a material effect on our financial condition. +- 76 - +Table of Contents +(10) +Quarterly Financial Data (Unaudited) +The sum of the earnings per common +share may not equal the corresponding annual amounts due to interim quarter rounding. +For the Quarter Ended in Fiscal 2016 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +47,160 +$ +51,259 +$ +50,665 +$ +46,998 +Gross profit +31,583 +33,572 +32,909 +29,723 +Net earnings +8,893 +9,091 +8,754 +5,491 +Basic earnings per common share +0.21 +0.22 +0.21 +0.13 +Diluted earnings per common share +0.21 +0.21 +0.21 +0.13 +Cash dividends per common share +0.20 +0.20 +0.20 +0.20 +For the Quarter Ended in Fiscal 2015 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +48,013 +$ +51,545 +$ +48,204 +$ +47,068 +Gross profit +29,237 +32,521 +30,331 +29,793 +Net earnings +7,901 +10,070 +9,102 +8,467 +Basic earnings per common share +0.19 +0.24 +0.22 +0.20 +Diluted earnings per common share +0.19 +0.24 +0.22 +0.20 +Cash dividends per common share +0.20 +0.20 +0.20 +0.20 +(11) +Subsequent Events +We evaluated subsequent events after the balance sheet +date of September 30, 2016 and there were no material subsequent events that required recognition or additional disclosure in these financial statements. +- 77 - +Table of Contents +ITEM 9. +CHANGES IN AND DISAGREE MENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE +Not applicable. +ITEM 9A. +CONTROLS AND PROCEDURES +As of September 30, 2016, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive +Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended. Based on +that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of September 30, 2016. Noting that the Company’s assessment of and conclusion on the effectiveness of its +internal control over financial reporting did not include the internal controls of Magellan Biosciences, Inc., which was acquired during fiscal 2016 and the results of which since the date of acquisition were included in the 2016 consolidated +financial statements, there have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal quarter that has materially affected, or is +reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2016. +Our internal control report is included in this Annual Report on Form 10-K after Item 8, under the caption “Management’s Report on Internal Control +over Financial Reporting.” +ITEM 9B. +OTHER INFORMATION +Not applicable. +P ART +III. +The information required by Items 10, 11, 12, 13 and 14, of Part III are incorporated by reference from the Registrant’s Proxy Statement for +its 2017 Annual Shareholders’ Meeting to be filed with the Commission pursuant to Regulation 14A. +- 78 - +Table of Contents +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) (1) and (2) FINANCIAL STATEMENTS AND SCHEDULES. +All financial statements and schedules required to be filed by Item 8 of this Form and included in this report have been so identified under Item 8. No +additional financial statements or schedules are being filed since the requirements of paragraph (c) under Item 15 are not applicable to Meridian. +(b) (3) EXHIBITS. +Exhibit Number +Description of Exhibit +3.1 +Articles of Incorporation, including amendments not related to Company name change (Incorporated by reference to Registration Statement No. 333-02613 on Form S-3 filed with the Securities and Exchange Commission on April 18, 1996 +and Meridian’s Form 8-K filed with the Securities and Exchange Commission on May 16, 2007) +3.2 +Amended Code of Regulations (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on November 13, 2012) +10.1* +Savings and Investment Plan Prototype Adoption Agreement (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2003) +10.2* +Amendment No. 1 to Supplemental Benefit Agreement Dated September 23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on September +25, 2014) +10.3* +Third Amended and Restated Employment Agreement Dated October 3, 2016 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on October 5, +2016) +10.4* +Letter Agreement Dated July 26, 2016 between Meridian and Richard L. Eberly (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2016) +10.5* +Executive Employment Agreement dated March 21, 2016 between Meridian and Amy Winslow (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2016) +10.6* +Dividend Reinvestment Plan (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 1999) +10.7* +2004 Equity Compensation Plan, amended and restated effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.8* +2012 Stock Incentive Plan, effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.9* +Fiscal 2017 Officer’s Performance Compensation Plan (Filed herewith) +10.10* +Form of Time-Based Restricted Share Unit Award Agreement dated November 9, 2016 (Filed herewith) +- 79 - +Table of Contents +10.11* +Form of Performance Award Restricted Share Unit Award Agreement dated November 9, 2016 (Filed herewith) +10.12* +Form of Meridian Bioscience, Inc. Change in Control Agreement dated August 4, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2016) +10.13 +Agreement and Plan of Merger among Meridian Bioscience, Inc., Mariner Merger Sub, Inc., Magellan Biosciences, Inc. and Ampersand 2006 Limited +Partnership as the Stockholder Representative dated as of March 24, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2016) +10.14 +Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc. Meridian Life Science, Inc. and Fifth Third Bank dated August 1, 2007 (Incorporated by reference to +Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2007) +10.14.1 +Term Note among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc. Meridian Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank dated March 22, 2016 (Incorporated by reference to +Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, 2016) +10.14.2 +Amended and Restated Revolving Note with Fifth Third Bank dated March 22, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, 2016) +10.14.3 +First Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., +Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated September 2, 2010 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.14.4 +Second Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., +Meridian Life Science, Inc. and Fifth Third Bank dated December 1, 2010 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.14.5 +Third Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc. and Fifth Third Bank dated September 15, 2012 (Incorporated by +reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2012) +10.14.6 +Fifth Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank dated April 21, 2015 +(Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, 2015) +10.14.7 +Sixth Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank dated March 22, 2016 +(Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, 2016) +13 +2016 Annual Report to Shareholders (1) +14 +Code of Ethics (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2003) +- 80 - +Table of Contents +21 +Subsidiaries of the Registrant (Filed herewith) +23 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +31.1 +Certification of Principal Executive Officer required by Rule 13a-14(a) (Filed herewith) +31.2 +Certification of Principal Financial Officer required by Rule 13a-14(a) (Filed herewith) +32 +Section 1350 Certification of Chief Executive Officer and Chief Financial Officer (Filed herewith) +101 +The following financial information from Meridian Bioscience Inc.’s Annual Report on Form 10-K for the fiscal year ended September 30, 2016 filed with the SEC on November 29, 2016, formatted in XBRL includes: (i) Consolidated +Statements of Operations for the years ended September 30, 2016, 2015 and 2014; (ii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2016, 2015 and 2014; (iii) Consolidated Statements of Cash Flows for the years +ended September 30, 2016, 2015 and 2014; (iv) Consolidated Balance Sheets as of September 30, 2016 and 2015; (v) Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2016, 2015 and 2014; and (vi) the Notes to +Consolidated Financial Statements +* +Management Compensatory Contracts +(1) +Only specific portions of the 2016 Annual Report to Shareholders are incorporated by reference in this Form 10-K as filed herewith. A supplemental paper copy of the 2016 Annual Report to Shareholders has been +furnished to the Securities and Exchange Commission for informational purposes only or will be posted on our website, www.meridianbioscience.com . +Meridian will provide shareholders with any exhibit upon the payment of a specified reasonable fee, which fee shall be limited to Meridian’s reasonable +expenses in furnishing such exhibit. +- 81 - +Table of Contents +SIGNATURES +Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +MERIDIAN BIOSCIENCE, INC. +By: +/s/ John A. Kraeutler +Date: +November 29, 2016 +John A. Kraeutler +Chairman of the Board and +Chief Executive Officer +We, the undersigned directors and officers of the Registrant, hereby severally constitute John A. Kraeutler and Melissa +A. Lueke, and each of them singly, our true and lawful attorneys with full power to them and each of them to sign for us, in our names in the capacities indicated below, any and all amendments to the Annual Report on Form 10-K filed with the +Securities and Exchange Commission. +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following +persons on behalf of the Registrant and in the capacities and on the dates indicated. +Signature +Capacity +Date +/s/ John A. Kraeutler +John A. Kraeutler +Chairman of the Board and Chief +Executive Officer +November 29, 2016 +/s/ Melissa A. Lueke +Melissa A. Lueke +Executive Vice President, Chief +Financial +Officer, and Secretary +(Principal Financial and Accounting Officer) +November 29, 2016 +/s/ James M. Anderson +James M. Anderson +Director +November 29, 2016 +/s/ Dwight E. Ellingwood +Dwight E. Ellingwood +Director +November 29, 2016 +/s/ John C. McIlwraith +John C. McIlwraith +Director +November 29, 2016 +/s/ David C. Phillips +David C. Phillips +Director +November 29, 2016 +/s/ Catherine A. Sazdanoff +Catherine A. Sazdanoff +Director +November 29, 2016 +- 82 - +Table of Contents +SCHEDULE II +Meridian Bioscience, Inc. +and +Subsidiaries +Valuation and Qualifying Accounts +(Dollars in thousands) +Years Ended +September 30, 2016, 2015 and 2014 +Description +Balance at +Beginning +of Period +Charged to +Costs and +Expenses +Deductions +Other (a) +Balance at +End of +Period +Year Ended September 30, 2016: +Allowance for doubtful accounts +$ +248 +$ +139 +$ +(69 +) +$ +16 +$ +334 +Inventory realizability reserves +2,456 +1,285 +(1,072 +) +11 +2,680 +Valuation allowances – deferred taxes +15 +327 +— +— +342 +Year Ended September 30, 2015: +Allowance for doubtful accounts +$ +272 +$ +73 +$ +(41 +) +$ +(56 +) +$ +248 +Inventory realizability reserves +2,942 +208 +(590 +) +(104 +) +2,456 +Valuation allowances – deferred taxes +8 +7 +— +— +15 +Year Ended September 30, 2014: +Allowance for doubtful accounts +$ +233 +$ +116 +$ +(68 +) +$ +(9 +) +$ +272 +Inventory realizability reserves +2,499 +1,325 +(834 +) +(48 +) +2,942 +Valuation allowances – deferred taxes +296 +8 +(296 +) +— +8 +(a) +Balances reflect the effects of currency translation and in 2016, the acquisition of Magellan. +- 83 - \ No newline at end of file diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/filing_metadata.csv b/raw/filings/0000794172/2016/0001193125-16-779250/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..9c9e6c5dbf629a7eac80c0ab46979b0add1cc908 --- /dev/null +++ b/raw/filings/0000794172/2016/0001193125-16-779250/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000794172,VIVO,MERIDIAN BIOSCIENCE INC,10-K,2016-11-29,2016-09-30,2016-11-29T18:24:05.000Z,0001193125-16-779250,d270799d10k.htm,ANNUAL REPORT,6692834,1,0,https://www.sec.gov/Archives/edgar/data/794172/000119312516779250/d270799d10k.htm,https://www.sec.gov/Archives/edgar/data/794172/000119312516779250/,2016,2016,1 diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/item1.txt b/raw/filings/0000794172/2016/0001193125-16-779250/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..2dfaa74ac178881eebd6994e382ae13b2bdc3c04 --- /dev/null +++ b/raw/filings/0000794172/2016/0001193125-16-779250/item1.txt @@ -0,0 +1,256 @@ +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science +company with principal businesses in (i) the development, manufacture, sale and distribution of diagnostic test kits, primarily for certain gastrointestinal, viral, respiratory, and parasitic infectious diseases, and elevated blood lead levels; and +(ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch reagents used by researchers and other diagnostic manufacturers. The Company was incorporated in Ohio in +1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +During March 2016, we acquired all of the outstanding common stock of +Magellan Biosciences, Inc., and its wholly-owned subsidiary Magellan Diagnostics, Inc. (collectively, “Magellan”), which is now reported as part of our Diagnostics operating segment. Headquartered near Boston, Massachusetts, Magellan +is a leading manufacturer of FDA-cleared products for the testing of blood to diagnose lead poisoning in children and adults. Magellan is the leading provider of point-of-care lead testing systems in the U.S. +- 5 - +Table of Contents +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, +Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the Securities and +Exchange Commission (SEC). These reports may also be read and copied at the SEC’s public reference room at 100 F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these +filings and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered part of this Annual Report on Form 10-K. +Reportable Segments +Our reportable segments are +Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio, which also serves as the Diagnostics segment’s base of manufacturing operations and research and development for infectious disease products. The +Diagnostics segment consists of manufacturing operations in Cincinnati, Ohio, and the sale and distribution of diagnostic test kits in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and +Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, or “ROW”). As previously noted, the Diagnostics segment includes the Company’s recent acquisition of Magellan, which is located +in Billerica, Massachusetts (near Boston). Its facility includes research, development, manufacturing, marketing, sales, and distribution operations. The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca +Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch reagents domestically and abroad, including +sales and business development offices in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. Financial information for Meridian’s reportable segments is included in Note 8 to the consolidated financial +statements. +Diagnostics Segment +Overview of +Products and Markets +Our primary source of revenues continues to be diagnostic products, with our Diagnostics segment providing 74% of +consolidated net revenues for fiscal 2016. Third-party revenues for this segment were $145,000, $146,000 and $142,000 for fiscal 2016, 2015 and 2014, respectively. As of September 30, 2016, our Diagnostics segment had approximately 440 +employees in seven countries. +Our diagnostic products provide accuracy, simplicity and speed; enable early diagnosis and treatment of common, acute +medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that (i) are conditions where rapid diagnosis impacts patient outcomes; (ii) have opportunistic demographic and disease +profiles; (iii) are underserved by current diagnostic products; and (iv) have difficult sample handling requirements (stool, blood, urine and other body fluids). This approach has allowed us to establish significant market share in our target +disease states. +- 6 - +Table of Contents +Our diagnostic products span a broad menu of testing platforms and technologies, and also include transport media +that store and preserve specimen samples from patient collection to laboratory testing. Our testing platforms include: +• +Isothermal DNA Amplification ( illumi gene brand) – high sensitivity, molecular platform that is suitable for virtually any size laboratory, whether centralized or decentralized; +provides flexibility to process from 1 to 10 tests per run in generally under one hour; and requires no batching of samples. +• +Rapid Immunoassay (TRU, Immuno Card and Immuno Card STAT! brands) – single-use immunoassays that can be used in point-of-care settings; have fast turnaround +times (generally under 20 minutes); and can reduce expensive send-outs for hospitals and outpatient clinics. +• +Enzyme-linked Immunoassay (PREMIER brand) – batch immunoassay platform that can process up to 96 tests per run; is highly accurate and economical; and is adaptable to automation. +• +Anodic Stripping Voltammetry (LeadCare brand) – electrical chemical sensor platform for quantitative determination of lead levels in blood. +Our diagnostic products are used principally in the detection of infectious diseases caused by various bacteria, viruses, parasites and pathogens, including +most notably the following general areas: +• +C. difficile – causative agent for antibiotic-associated diarrhea from a hospital-acquired infection +• +Foodborne – Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy) +• +H. pylori – stomach ulcers +• +Respiratory – Group A Streptococcus , M. pneumoniae (Mycoplasma) and Bordetella pertussis , among tests for other diseases +• +Women’s Health & Sexually Transmitted Diseases (“STD”) – Group B Streptococcus , Chlamydia trachomatis , Neisseria gonorrhea , Herpes Simplex Virus Type 1 & Type 2 +Our diagnostics products also include Magellan’s LeadCare brand of tests for quantitative determination of blood lead levels. +Our product portfolio includes over 140 diagnostic tests and transport media, and is marketed to acute care hospitals, reference laboratories, outpatient +clinics and physician office laboratories in over 70 countries around the world. +- 7 - +Table of Contents +We continue to invest in new product development for our molecular testing platform, +illumi gene . This platform now has the following commercialized tests (assays): +1. +illumi gene C. difficile – commercialized in August 2010 +2. +illumi gene Group B Streptococcus (Group B Strep or GBS) – commercialized in December 2011 +3. +illumi gene Group A Streptococcus (Group A Strep) – commercialized in September 2012 +4. +illumi gene Mycoplasma ( M. pneumoniae; walking pneumonia) – commercialized in June 2013 +5. +illumi gene Bordetella pertussis (whooping cough) – commercialized in March 2014 +6. +illumi gene Chlamydia trachomatis – commercialized outside of U.S. in February 2015 +7. +illumi gene Neisseria gonorrhea – commercialized outside of U.S. in February 2015 +8. +illumi gene HSV 1&2 (Herpes Simplex Virus Type 1 & Type 2) – commercialized in July 2015 +9. +illumi gene Malaria – commercialized outside of U.S. in February 2016 +10. +illumi gene Mycoplasma Direct ( M. pneumoniae; walking pneumonia) – commercialized in June 2016 +We have several additional illumi gene tests in development, a robust pipeline of illumi gene opportunities and a plan +to continue adding new assays to our illumi gene platform menu. +We believe that our illumi gene system has been +well-accepted in our global markets. We now have over 1,500 customer account placements. Of these account placements, approximately 1,300 accounts have completed evaluations and validations and are regularly purchasing product, with the +balance of our account placements being in some stage of product evaluation and/or validation. Of our account placements, we have nearly 450 accounts that are regularly purchasing, evaluating and/or validating two or more assays. +Market Trends +The global market for infectious +disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. More importantly, within this market, there is a continuing shift from +conventional testing, which requires highly trained personnel and lengthy turnaround times for test results, to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The increasing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. With rapid and accurate +diagnoses of infectious diseases, physicians can pinpoint appropriate therapies quickly, leading to faster recovery, shorter hospital stays and lower overall treatment cost. Integrated Delivery Networks (IDNs) and Accountable Care Organizations +(ACOs) in our U.S. market have the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with IDNs, ACOs and health care systems that +are transitioning from fee-for-service compensation models, to value based reimbursement. Our C. difficile , Group B Streptococcus , Group A Streptococcus and H. pylori products are all examples of how a highly accurate +diagnostic test on the front end can mitigate or reduce down-stream costs for antibiotic use, symptom-relieving drugs and hospital stays. +- 8 - +Table of Contents +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing +organizations and integrated delivery networks, consolidation among reference laboratories, and acquisition of physician practices by hospitals, health systems, and for-profit specialty health care companies. We utilize multi-year supply agreements +to secure our business where we deem appropriate. +Cost containment pressures have also affected health care systems outside the U.S., particularly in +Europe, where the health care systems are generally government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing and Distribution +Our Diagnostics +segment’s sales and distribution network consists of the following for each of the broad geographic regions we serve: +North +America +In North America, our sales and distribution network consists of a direct sales force (U.S. only) complemented by independent +distributors. The use of independent distributors in the U.S. allows our products to reach any size health care facility and also provides our customers the option to purchase our products directly from Meridian or through an authorized +distributor. Two independent distributors in the U.S. accounted for 10% or more of consolidated net revenues in fiscal 2016, 2015 and 2014: Cardinal Healthcare Corporation and Thermo Fisher Scientific. Our revenues from Cardinal were +approximately $20,000, $29,000 and $28,000 during fiscal 2016, 2015 and 2014, respectively. Our revenues from Thermo Fisher were approximately $20,000, $25,000 and $23,000 during fiscal 2016, 2015 and 2014, respectively. +EMEA +In EMEA, our sales +and distribution network consists of direct sales forces in Belgium, France, Holland and Italy, and independent distributors in other European countries, Africa and the Middle East. We have implemented a direct sales presence in Germany and the +U.K. for our illumi gene products, and utilize independent distributors for our immunoassay products. We maintain a distribution center near Milan, Italy. +ROW +With the exception +of Australia, where we utilize a direct sales force, we utilize independent distributors throughout the ROW. +- 9 - +Table of Contents +Competition +Our major competitors in molecular diagnostics are Cepheid and Becton Dickinson, who have systems with multiple-assay menus. We also face competition in +molecular diagnostics, but to a lesser degree, from companies such as Alere, Great Basin, Nanosphere and Quidel. These latter companies have a limited commercial menu and tend to compete strictly on price. We believe that our molecular +platform offers a number of competitive features: +• +Molecular assay sensitivity that is comparable to higher costing PCR; +• +Low capital investment with no instrument service cost; +• +Small footprint that is portable and does not consume much laboratory space; and +• +Product menu that fits with initiatives to improve clinical and economic outcomes. +Our major competitors in +rapid immunoassay diagnostics are primarily Alere and Quidel. These companies tend to compete strictly on price. For blood lead testing, we believe we have the only FDA-cleared, CLIA-waived point-of-care test available +commercially. Other blood lead testing systems in use include Graphite Furnace Atomic Absorption Spectroscopy, which requires a highly-skilled technician and larger laboratory space to operate, in addition to not being portable or suitable for +point-of-care use. We believe that with the breadth and depth of our product portfolio, we are well positioned for the clinical laboratory. +Research and Development +Our Diagnostics +segment’s research and development organization for infectious disease products is located at our corporate headquarters in Newtown, Ohio, a suburb of Cincinnati, and has expertise in biochemistry, immunology, mycology, bacteriology, virology, +parasitology, and molecular biology. Our Magellan business has a dedicated research and development team in Billerica, Massachusetts. Research and development expenses for the Diagnostics segment for fiscal 2016, 2015 and 2014 were +approximately $11,000, $10,000 and $10,000, respectively. Our research and development activities are focused on new product and new technology development, new applications for our existing technologies, and improvements to existing +products. Research and development efforts may occur in-house or with collaborative partners. We believe that new product development is a key source for sustaining revenue growth. The products within our +illumi gene molecular platform, H. pylori product family and blood lead testing family were developed solely in-house, or substantially so. +Manufacturing +Our immunoassay and molecular +products require the production of highly specific and sensitive antigens, antibodies, primers and enzymes. While we produce substantially all of our own requirements including monoclonal and polyclonal antibodies, and a variety of fungal, +bacterial and viral antigens, currently a number of the raw materials used in our products, including our illumi gene molecular products, are purchased from outside vendors. With the expansion of our molecular diagnostic +manufacturing capacity at our Cincinnati, Ohio location in recent years, we brought in-house certain molecular component manufacturing that was previously outsourced. Our blood lead testing products require the production of electrical chemical +sensors, for which we produce all of our own requirements. We believe that we have sufficient manufacturing and sourcing capacity for anticipated growth over the next several years. +- 10 - +Table of Contents +Intellectual Property, Patents and Licenses +We own or license U.S. and foreign patents, most of which are for selected products manufactured by our Diagnostics segment. These patents are used in our +manufacturing processes for selected products (method patents) or may relate to the design of the test device technology format (design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully +replicate our production and manufacturing technologies and processes. Our employees are required to sign confidentiality and non-disclosure agreements designed to protect our proprietary products. +The patents for our illumi gene products, which represented 20% and 21% of consolidated revenues for fiscal 2016 and fiscal 2015, +respectively, are licensed from a third party, Eiken Chemical Co., Ltd., under a non-exclusive license agreement and expire between 2020 and 2022. These patents were issued in the U.S., European Community and other countries. The term +of our license agreement runs until the last patent expires in 2022, at which point we will be free to practice the patents without any restriction or royalty obligation. +The patents for our H. pylori products, which represented 15% and 14% of consolidated revenues for fiscal 2016 and fiscal 2015, respectively, are +owned by us and expired in May 2016 in the U.S., and will expire in fiscal 2017 in countries outside the U.S. We expect competition with respect to our H. pylori products to increase in fiscal 2017 as we currently market the only +FDA-cleared tests to detect H. pylori antigen in stool samples. Such competition may have an adverse impact on our selling prices for these products or our ability to retain business at prices acceptable to us, and consequently, +adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to mitigate competition, our product development pipeline includes multiple new product initiatives for the detection of H. +pylori . We are unable to provide assurances that we will be successful with any mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and +gross profit. +Government Regulation +Our +diagnostic products are regulated by the Food & Drug Administration (FDA) as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (FDCA). Under the FDCA, medical devices are classified into one of three classes (i.e., +Class I, II or III). Class I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally must receive “pre-market approval” from the FDA as to safety and +effectiveness. +- 11 - +Table of Contents +Each of the diagnostic products currently marketed by us in the United States has been cleared by the FDA +pursuant to the 510(k) clearance process or is exempt from such requirements. We believe that most, but not all, products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all +Class II devices, will be eligible for 510(k) clearance; however, we can make no assurances in this regard. Meridian’s TRU FLU rapid influenza assay was cleared in 2006 as a Class I device. In May 2014, the FDA proposed reclassifying +rapid influenza assays as a Class II device, requiring the submission of a new 510(k) application and subjecting TRU FLU and similar competitive devices to increased requirements for sensitivity. If the proposed rule becomes effective, Meridian +will have one year to bring its assay up to the new requirements or remove it from the market. Sales of the TRU FLU product totaled approximately $1,000 in fiscal 2016. +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, largely similar to that of the FDA. +Meridian’s Cincinnati manufacturing facility is certified to ISO 13485:2012, and the Magellan facility in Billerica, Massachusetts is certified to ISO +9001:2008 and ISO 13485:2003. +Medical Device Tax +On January 1, 2013, the medical device tax established as part of the U.S. health care reform legislation became effective and as a result, the Company made +its first required tax deposit near the end of January 2013. During fiscal 2016, 2015 and 2014, the Company recorded to cost of sales approximately $500, $1,900 and $1,750, respectively, of medical device tax expense related to this +legislation. During December 2015, the Consolidations Appropriations Act of 2016 imposed a two-year moratorium on this excise tax effective January 1, 2016. During calendar years 2016 and 2017, this moratorium would result in approximately +$2,000 of savings each year. We are unable to predict any future legislative changes or developments related to this moratorium or excise tax. +Seasonal Factors and Sporadic Outbreaks +Our +principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory, and parasitic infectious diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in +nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as the H1N1 influenza outbreak during fiscal 2009. While we believe that the breadth of our diagnostic product lines reduces the risk +that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be impacted period over period by such factors. +- 12 - +Table of Contents +Life Science Segment +Overview of Products and Markets +Our Life Science +segment’s business focuses on the development, manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers, agri-bio companies and other +diagnostic manufacturing companies. Third-party revenues for this segment were approximately $51,000, $49,000 and $47,000 for fiscal 2016, 2015 and 2014, respectively. As of September 30, 2016, our Life Science segment had approximately +210 employees in seven countries. +Most of the revenues for our Life Science segment currently come from the manufacture, sale and distribution of bulk +antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies focused on the development of immunoassay and molecular tests. Approximately 65% of +Life Science revenues are generated from the industrial market, defined as diagnostic manufacturers and the agriculture industry. This continues to be an increasing focus of our Bioline molecular component business, which historically focused +on the academic/research market that comprises the remaining 35% of Life Science revenues. We utilize direct sales teams in key countries such as the U.S., the U.K., Germany, France, Australia and Singapore. Opened in 2013, the Singapore +sales and business development office is designed to increase our presence and our revenue opportunities in Asia for both molecular and immunoassay components. Additionally, in order to further pursue revenue opportunities in Asia, and China in +particular, during fiscal 2015 we opened a representative office in Beijing, China. We utilize a network of distributors in other major countries. During fiscal 2016, 18% of third-party revenues for this segment were from two diagnostic +manufacturing customers. +Products such as antibodies, antigens and reagents are marketed primarily to diagnostic manufacturing customers as a source of +raw materials for their immunoassay products, or as an outsourced step in their manufacturing processes. For example, we supply a number of major diagnostic manufacturers with proteins used to detect hepatitis A and rubella. These products +are typically sold in bulk quantities, and may also be custom-designed for a particular manufacturer’s requirements. Sales efforts are focused on multi-year supply arrangements in order to provide stability in volumes and pricing. We +believe this benefits both us and our customers. +Molecular biology products such as PCR/qPCR reagents, nucleotides and competent cells are marketed to +academic/research and industrial customers. These products are used in measuring DNA and RNA in clinical and agricultural applications. These reagents improve the purity, yield and speed of PCR reactions. Products such as MyTaq and SensiFAST are examples of this type of PCR/qPCR reagent. +- 13 - +Table of Contents +Market Trends +As certain global markets become increasingly accessible to us, most notably China, geographic expansion continues to be a significant strategy for our Life +Science segment, along with further penetration into industrial markets with our molecular products. +Competition +The market for bulk biomedical reagents is highly competitive. Important competitive factors include product quality, price, customer service and +reputation. We face competitors, many of which have greater financial, research and development, sales and marketing, and manufacturing resources, and where sole-source supply arrangements do not exist. Customers also may choose to +manufacture their biomedical reagents in-house rather than purchase from outside vendors such as Meridian. +The academic/research market is highly +fragmented. Individual purchases are typically of small quantities. The breadth of product offerings, quality, price and service, including on-line capabilities and technical resources, are important factors to building customer loyalty +and repeat purchases. +Research and Development +Research and development expenses for our Life Science segment for each of fiscal 2016, 2015 and 2014 were approximately $3,000. The primary focus of this +research and development organization is development of new molecular reagent products. +Manufacturing and Government Regulation +Our Life Science U.S. facilities are ISO 9001:2008 certified and our Bioline facilities in the U.K. and Germany are ISO 13485:2012 +certified. Additionally, where appropriate, our Life Science facilities comply with Regulation EC 1069:2009. +Acquisitions +Acquisitions have played an important role in the growth of our businesses. Our acquisition objectives include, among other things: (i) enhancing product +offerings; (ii) improving product distribution capabilities; (iii) providing access to new markets; and/or (iv) providing access to key biologicals or new technologies that lead to new products. Although we cannot provide assurance that we will +consummate additional acquisitions in the future, nor can we provide assurance that any acquisitions will accomplish these objectives, we expect that the potential for acquisitions will continue to provide opportunities for revenue and earnings +growth in the future. +As previously noted in the Overview section, during March 2016, we acquired all of the outstanding common stock of +Magellan. Headquartered near Boston, Massachusetts, Magellan is a leading manufacturer of FDA-cleared products for the testing of blood to diagnose lead poisoning in children and adults. Magellan is the leading provider of point-of-care +lead testing systems in the U.S. +- 14 - +Table of Contents +International Markets +International markets are an important source of revenues and future growth opportunities for both of our segments. For both segments combined, revenues +from customers located outside of the Americas approximated $52,000 or 26% of consolidated fiscal 2016 revenues, $49,000 or 25% of consolidated fiscal 2015 revenues, and $55,000 or 29% of consolidated fiscal 2014 revenues. We expect to continue +to look to international markets as a source of revenue growth in the future. +During fiscal 2016, currency exchange had an approximate $1,700 unfavorable +impact on revenues; $700 within the Diagnostics segment and $1,000 within the Life Science segment. This compares to currency exchange rates having an approximate $4,700 unfavorable impact on revenues in fiscal 2015; $3,200 within the +Diagnostics segment and $1,500 within the Life Science segment. Due to natural hedge relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net earnings was not significant +during fiscal 2016, 2015 or 2014. +Environmental +We +are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. \ No newline at end of file diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/item13.txt b/raw/filings/0000794172/2016/0001193125-16-779250/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..f1c64cbda407846c1e39ac77c9096478d2a81826 --- /dev/null +++ b/raw/filings/0000794172/2016/0001193125-16-779250/item13.txt @@ -0,0 +1,3 @@ +Item 13 +Certain Relationships and Related Transactions, and Director Independence +78 \ No newline at end of file diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/item9a.txt b/raw/filings/0000794172/2016/0001193125-16-779250/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..451806da26eec3ba20655282632e0dee5f001193 --- /dev/null +++ b/raw/filings/0000794172/2016/0001193125-16-779250/item9a.txt @@ -0,0 +1,10 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +As of September 30, 2016, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive +Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended. Based on +that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of September 30, 2016. Noting that the Company’s assessment of and conclusion on the effectiveness of its +internal control over financial reporting did not include the internal controls of Magellan Biosciences, Inc., which was acquired during fiscal 2016 and the results of which since the date of acquisition were included in the 2016 consolidated +financial statements, there have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal quarter that has materially affected, or is +reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2016. +Our internal control report is included in this Annual Report on Form 10-K after Item 8, under the caption “Management’s Report on Internal Control +over Financial Reporting.” \ No newline at end of file diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/rp_note.txt b/raw/filings/0000794172/2016/0001193125-16-779250/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000794172/2016/0001193125-16-779250/rpt_disclosure.txt b/raw/filings/0000794172/2016/0001193125-16-779250/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..c7bad3cd2e9f6a5176a983b5b981d9d9621ecea4 --- /dev/null +++ b/raw/filings/0000794172/2016/0001193125-16-779250/rpt_disclosure.txt @@ -0,0 +1,15 @@ +TRANSACTIONS WITH RELATED PERSONS +During fiscal 2017, the Company leased certain office space from an entity controlled by Marco G. Calzavara, President and Managing Director, Meridian +Bioscience Europe. Payments made under such arrangements during fiscal 2017 totaled approximately $150,000. +Nasdaq rules require the +Company to conduct an appropriate review of related party transactions required to be disclosed by the Company pursuant to SEC Regulation S-K Item 404 for potential conflict of interest situations on an +ongoing basis and that all such transactions must be approved by the Audit Committee or another Committee comprised of independent Directors. As a result, the Audit Committee annually reviews all such related party transactions and approves each +related party transaction if it determines that it is in the best interests of the Company. Additionally, the Audit Committee’s Charter provides it the authority to review, approve and monitor transactions involving the Company and +“related persons” (Directors and Executive Officers or their immediate family members, or shareholders owning five percent or greater of the Company’s outstanding stock). This also covers any related person transaction that meets the +minimum threshold for disclosure in the proxy statement under the relevant SEC rules (generally, transactions involving amounts exceeding $120,000 in which a related person has a direct or indirect material interest). In +considering the transaction, the Audit Committee may consider all relevant factors, including, as applicable: (i) the Company’s business rationale for entering into the transaction; (ii) the alternatives to entering into a related +person transaction; (iii) whether the transaction is on terms comparable to those available to third parties, or in the case of employment relationships, to employees generally; (iv) the potential for +15 +Table of Contents +the transaction to lead to an actual or apparent conflict of interest and any safeguards imposed to prevent such actual or apparent conflicts; and (v) the overall fairness of the transaction +to the Company. This policy is included in the Company’s Employee Handbook. The approval of such related person transactions are evidenced by internal Company resolutions or memoranda. \ No newline at end of file diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/filing.txt b/raw/filings/0000794172/2017/0001193125-17-354808/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..ad4ab8ba6ac2c05be4b6ba7ac48e646843d22148 --- /dev/null +++ b/raw/filings/0000794172/2017/0001193125-17-354808/filing.txt @@ -0,0 +1,4358 @@ +10-K +1 +d472698d10k.htm +ANNUAL REPORT +Annual Report +Table of Contents +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +FOR ANNUAL +AND TRANSITION REPORTS +PURSUANT TO SECTIONS 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2017. +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM +TO +Commission File No. 0-14902 +MERIDIAN BIOSCIENCE, INC. +3471 River +Hills Drive +Cincinnati, Ohio 45244 +IRS Employer ID No. 31-0888197 +Incorporated under the Laws of Ohio +Phone: (513) 271-3700 +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange of which +registered +Common Shares, No Par Value +The NASDAQ Stock Market LLC +(NASDAQ Global Select Market) +Securities Registered Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the +registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ☐ NO ☒ +If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or +15(d) of the Securities Exchange Act. YES ☐ NO ☒ +Table of Contents +Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by +Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 +days. YES ☒ NO ☐ +Indicate by check mark whether the registrant has +submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or +for such shorter period that the registrant was required to submit and post such files). YES ☒ NO ☐ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this Chapter) is not contained +herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or +emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +☒ +Accelerated filer +☐ +Non-accelerated filer +☐ (Do not check if a smaller reporting company) +Smaller reporting company +☐ +Emerging Growth Company +☐ +Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). YES ☐ NO ☒ +If an emerging +growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange +Act. ☐ +The aggregate market value of Common Shares held by non-affiliates as of March 31, +2017 was $574,070,312 based on a closing sale price of $13.80 per share on March 31, 2017. As of October 31, 2017, 42,216,567 no par value Common Shares were issued and outstanding. +Documents Incorporated by Reference +Portions of +the Registrant’s Annual Report to Shareholders for the fiscal year ended September 30, 2017 furnished to the Commission pursuant to Rule 14a-3(b) are incorporated by reference in Part II as specified +and portions of the Registrant’s Proxy Statement to be filed with the Commission for its 2018 Annual Shareholders’ Meeting are incorporated by reference in Part III as specified. +Table of Contents +MERIDIAN BIOSCIENCE, INC. +INDEX TO ANNUAL REPORT +ON FORM 10-K +Page +Part I +Item 1 +Business +5 +Item 1A +Risk Factors +15 +Item 1B +Unresolved Staff Comments +26 +Item 2 +Properties +27 +Item 3 +Legal Proceedings +27 +Item 4 +Mine Safety Disclosures +28 +Part II +Item 5 +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer +Purchases of Equity Securities +28 +Item 6 +Selected Financial Data +29 +Item 7 +Management’s Discussion and Analysis of Financial Condition and Results of +Operations +29 +Item 7A +Quantitative and Qualitative Disclosures about Market Risk +47 +Item 8 +Financial Statements and Supplementary Data +48 +Item 9 +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +82 +Item 9A +Controls and Procedures +82 +Item 9B +Other Information +84 +Part III +Item 10 +Directors, Executive Officers and Corporate Governance +84 +Item 11 +Executive Compensation +84 +Item 12 +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder +Matters +84 +Item 13 +Certain Relationships and Related Transactions, and Director Independence +84 +Item 14 +Principal Accountant Fees and Services +84 +Item 15 +Exhibits and Financial Statement Schedules +85 +Item 16 +Form 10-K Summary +88 +FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements. The Private Securities Litigation Reform Act of +1995 provides a safe harbor from civil litigation for forward-looking statements accompanied by meaningful cautionary statements. Except for historical information, this report contains forward-looking statements within the meaning of +Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, which may be identified by words such as “estimates”, “anticipates”, “projects”, +“plans”, “seeks”, “may”, “will”, “expects”, “intends”, “believes”, “should” and similar expressions or the negative versions thereof and which also may be identified by +their context. All statements that address operating performance or events or developments that Meridian expects or anticipates will occur in the future, including, but not limited to, statements relating to per share diluted earnings and revenue, +are forward-looking statements. Such statements, whether expressed or implied, are based upon current expectations of the Company and speak only as of the date made. Specifically, Meridian’s forward-looking statements are, and will be, based on +management’s then-current views and assumptions regarding future events and operating performance. Meridian assumes no obligation to publicly update or revise any forward-looking statements even if experience or future changes make it clear +that any projected results expressed or implied therein will not be realized. These statements are subject to various risks, uncertainties and other factors that could cause actual results to differ materially, including, without limitation, the +following: Meridian’s operating results, financial condition and continued growth depends, in part, on its ability to introduce into the marketplace enhancements of existing products or new products that incorporate technological advances, meet +customer requirements and respond to products developed by Meridian’s competition, its ability to effectively sell such products and its ability to successfully expand and effectively manage increased sales and marketing operations. While +Meridian has introduced a number of internally developed products, there can be no assurance that it will be successful in the future in introducing such products on a timely basis or in protecting its intellectual property, and unexpected or costly +manufacturing costs associated with the ramp up of new products could cause actual results to differ from expectations. Meridian relies on proprietary, patented and licensed technologies. As such, the Company’s ability to protect its +intellectual property rights, as well as the potential for intellectual property litigation, would impact its results. Ongoing +Table of Contents +consolidations of reference laboratories and formation of multi-hospital alliances may cause adverse changes to pricing and distribution. Recessionary pressures on the economy and the markets in +which our customers operate, as well as adverse trends in buying patterns from customers, can change expected results. Costs and difficulties in complying with laws and regulations, including those administered by the United States Food and Drug +Administration, can result in unanticipated expenses and delays and interruptions to the sale of new and existing products, as can the uncertainty of regulatory approvals and the regulatory process. The international scope of Meridian’s +operations, including changes in the relative strength or weakness of the U.S. dollar and general economic conditions in foreign countries, can impact results and make them difficult to predict. One of Meridian’s growth strategies is the +acquisition of companies and product lines. There can be no assurance that additional acquisitions will be consummated or that, if consummated, will be successful and the acquired businesses will be successfully integrated into Meridian’s +operations. There may be risks that acquisitions may disrupt operations and may pose potential difficulties in employee retention, and there may be additional risks with respect to Meridian’s ability to recognize the benefits of acquisitions, +including potential synergies and cost savings or the failure of acquisitions to achieve their plans and objectives. Meridian cannot predict the outcome of goodwill impairment testing and the impact of possible goodwill impairments on +Meridian’s earnings and financial results. Meridian cannot predict the possible impact of U.S. health care legislation enacted in 2010 – the Patient Protection and Affordable Care Act, as amended by the Health Care and Education +Reconciliation Act – and any modification or repeal of any of the provisions thereof initiated by Congress or the presidential administration, and any similar initiatives in other countries on its results of operations. Efforts to reduce the +U.S. federal deficit, the outcome of tax reform legislation, breaches of Meridian’s information technology systems and natural disasters and other events could have a materially adverse effect on Meridian’s results of operations and +revenues. We have identified a material weakness in our internal control over financial reporting that, if not properly corrected, could materially adversely affect our operations and result in material misstatements in our financial statements. In +addition to the factors described in this paragraph, as well as those factors identified from time to time in our filings with the Securities and Exchange Commission, Part I, Item 1A Risk Factors of this Annual Report on Form 10-K contains a list and description of uncertainties, risks and other matters that may affect the Company. Readers should carefully review these forward-looking statements and risk factors and not place undue +reliance on our forward-looking statements. +Table of Contents +PART I. +This Annual Report on Form 10-K includes forward-looking statements about our business and results of operations that +are subject to risks and uncertainties. See “Forward-Looking Statements” above. Factors that could cause or contribute to such differences include those discussed in Item 1A. “Risk Factors.” In addition to the risk factors +discussed herein, we are also subject to additional risks and uncertainties not presently known to us or that we currently deem immaterial. If any of these risks and uncertainties develops into actual events, our business, financial condition or +results of operations could be adversely affected. +Unless the context requires otherwise, references in this Annual Report on Form 10-K to “Meridian,” “we,” “us,” “our,” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +In the discussion that follows, all dollars and shares are in thousands (both tables and text), except per share data. +This Annual Report on Form 10-K refers to trademarks such as TRU +FLU ® , Immuno Card ® , Immuno Card STAT! ® , MyTaq ™ , SensiFAST ™ , PREMIER ® and LeadCare ® , which are protected under applicable intellectual property laws and are our property. Solely for convenience, our trademarks and tradenames referred to in this Form 10-K may appear without the ® or ™ symbols, but such references are not intended to indicate +in any way that we will not assert, to the fullest extent under applicable law, our rights to these trademarks and tradenames. +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in (i) the development, manufacture, sale and distribution of +diagnostic test kits, primarily for certain gastrointestinal, viral, respiratory, and parasitic infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, +nucleotides, competent cells, and bioresearch reagents used by researchers and other diagnostic manufacturers. The Company was incorporated in Ohio in 1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +During March 2016, we acquired all of the outstanding common stock of Magellan Biosciences, Inc., and its wholly-owned subsidiary Magellan Diagnostics, Inc. +(collectively, “Magellan”), which is now reported as part of our Diagnostics operating segment. Headquartered near Boston, Massachusetts, Magellan is a leading manufacturer of products cleared by the Food & Drug Administration +(“FDA”) for the point-of-care testing of capillary blood to diagnose lead poisoning in children and adults. Further details of the Magellan acquisition are set +forth in Note 2 of the accompanying Consolidated Financial Statements. +- 5 - +Table of Contents +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments thereto, free of charge through this website, as +soon as reasonably practicable after such material has been electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). These reports may also be read and copied at the SEC’s public reference room at 100 +F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these filings +and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered part of this Annual Report on Form 10-K. +Reportable Segments +Our reportable segments are +Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. Detailed information related to the reportable segments can be found in the following locations within this Annual Report on Form +10-K: +Type of Segment Information +Location within Annual Report on Form 10-K +Physical locations and activities +Item 2. “Properties” +Revenue by geographic region +Item 7. “Management’s Discussion and Analysis of Financial Condition & Results of Operations” (hereafter “MD&A”) +Financial information +Note 8 of Consolidated Financial Statements +Diagnostics Segment +Overview of Products and Markets +Our primary +source of revenues is clinical diagnostic products, with our Diagnostics segment providing 71% of consolidated net revenues for fiscal 2017. Third-party revenues for this segment were approximately $144,000, $145,000 and $146,000 for fiscal 2017, +2016 and 2015, respectively. As of September 30, 2017, our Diagnostics segment had approximately 420 employees in seven countries. +Our clinical +diagnostic products provide accuracy, simplicity and speed; enable early diagnosis and treatment of common, acute medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that +(i) are conditions where rapid diagnosis impacts patient outcomes; (ii) have opportunistic demographic and disease profiles; (iii) are underserved by current diagnostic products; and/or (iv) have difficult sample handling +requirements (e.g., stool). This approach has allowed us to establish significant market share in our target disease states. +- 6 - +Table of Contents +Our clinical diagnostic products span a broad menu of testing platforms and technologies, and also include +transport media that store and preserve specimen samples from patient collection to laboratory testing. Our testing platforms include: +• +Isothermal DNA Amplification ( illumi gene brand) – high sensitivity, molecular platform that is suitable for virtually any moderately-complex laboratory, whether centralized or +decentralized; provides flexibility to process from 1 to 10 tests per run in generally under one hour; and requires no batching of samples. +• +Rapid Immunoassay (TRU, Immuno Card and Immuno Card STAT! brands) – single-use immunoassays that have fast turnaround times +(generally under 20 minutes); and can reduce expensive send-outs for hospitals and outpatient clinics. +• +Enzyme-linked Immunoassay (PREMIER brand) – batch immunoassay platform that can process up to 96 tests per run; is highly accurate and economical; and is adaptable to +automation. +• +Anodic Stripping Voltammetry (LeadCare brand) – electrical chemical sensor platform for quantitative determination of lead levels in blood. +Our clinical diagnostic products are used principally in the detection of infectious diseases caused by various bacteria, viruses, parasites and pathogens, +including most notably the following general areas: +• +C. difficile – causative agent for antibiotic-associated diarrhea from a hospital-acquired infection +• +Foodborne – Enterohemorrhagic E. coli (EHEC) and Campylobacter jejuni (Campy) +• +H. pylori – stomach ulcers +• +Respiratory – Group A Streptococcus (strep throat), M. pneumoniae (Mycoplasma) and Bordetella pertussis (whooping cough), among tests for other diseases +• +Women’s Health & Sexually Transmitted Diseases (“STD”) – Group B Streptococcus , Chlamydia trachomatis , Neisseria gonorrhea , Herpes Simplex Virus +Type 1 & Type 2 +Our clinical diagnostics products also include Magellan’s LeadCare brand of tests for quantitative determination +of blood lead levels. +Our product portfolio includes over 140 diagnostic tests and transport media, and is marketed to acute care hospitals, reference +laboratories, outpatient clinics and physician office laboratories in over 70 countries around the world. +- 7 - +Table of Contents +We continue to invest in new product development for our molecular testing platform, and this platform now has +nine commercialized tests spanning hospital acquired infections, women’s health, respiratory, sexually transmitted diseases, and tropical diseases. As of September 30, 2017, our illumi gene Malaria test has been placed +in nearly 150 accounts in the EMEA region (i.e., Europe, Middle East and Africa) for use as a screening test for travelers returning to Europe from endemic areas in Africa. Our efforts to develop market channels in the endemic areas of Africa +continue, as we work to convince policy-makers of the advantages of a more accurate molecular test to assist in efforts to eradicate malaria. +We believe +that our illumi gene system has been well-accepted in our global markets. We now have nearly 1,650 customer account placements. Of these account placements, approximately 1,375 accounts have completed evaluations and validations +and are regularly purchasing product, with the balance of our account placements being in some stage of product evaluation and/or validation. Of our account placements, we have nearly 600 accounts that are regularly purchasing, evaluating and/or +validating two or more assays. +Our current research and development pipeline for immunoassay products includes a new instrument that utilizes fluorescent +chemistry and has colorimetric capabilities. This new platform is being branded under the “Curian” name. During the first half of fiscal 2018, we expect to submit a 510(k) to the FDA for one or more of our existing rapid +immunoassay tests using the colorimetric capabilities of the Curian instrument. During the second half of fiscal 2018, we expect to submit a 510(k) to the FDA for our first fluorescent assay, a combination C.difficile common antigen +(GDH) and toxin (A/B) test. Looking forward into fiscal 2019 and 2020, we expect to develop additional rapid immunoassay tests using the Curian fluorescent chemistry. +Market Trends +The global market for infectious +disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. More importantly, within this market, there is a continuing shift from +conventional testing, which requires highly trained personnel and lengthy turnaround times for test results, to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The increasing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. With rapid and accurate diagnoses +of infectious diseases, physicians can pinpoint appropriate therapies quickly, leading to faster recovery, shorter hospital stays and lower overall treatment cost. Integrated Delivery Networks (“IDNs”) and Accountable Care Organizations +(“ACOs”) in our U.S. market have the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with IDNs, ACOs and health care +systems that are transitioning from fee-for-service compensation models, to value based reimbursement. Our C. difficile , Group B Streptococcus , Group A +Streptococcus and H. pylori products are all examples of how a highly accurate diagnostic test on the front end can mitigate or reduce down-stream costs for antibiotic use, symptom-relieving drugs and hospital stays. +- 8 - +Table of Contents +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing +organizations and IDNs, consolidation among reference laboratories, hospital laboratories being operated by large reference laboratories, and acquisition of physician practices by hospitals, health systems, and +for-profit specialty health care companies. We utilize multi-year supply agreements to secure our business where we deem appropriate. +Cost containment pressures have also affected health care systems outside the U.S., particularly in Europe, where the health care systems are generally government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing and Distribution +Our Diagnostics +segment’s sales and distribution network consists of the following for each of the broad geographic regions we serve: +United +States +In the U.S., our sales and distribution network consists of a direct sales force complemented by independent distributors. The +use of independent distributors allows our products to reach any size health care facility and also provides our customers the option to purchase our products directly from Meridian or through an authorized distributor. Two independent distributors +accounted for 10% or more of consolidated revenues in fiscal 2017, 2016 and 2015: Cardinal Healthcare Corporation and Thermo Fisher Scientific. Our revenues from Cardinal were approximately $23,000, $20,000 and $29,000 during fiscal 2017, 2016 and +2015, respectively. Our revenues from Thermo Fisher were approximately $18,000, $20,000 and $25,000 during fiscal 2017, 2016 and 2015, respectively. +EMEA +In EMEA, our sales +and distribution network consists of direct sales forces in Belgium, France, Holland and Italy, and independent distributors in other European countries, Africa and the Middle East. We have implemented a direct sales presence in Germany and the U.K. +for our illumi gene products, and utilize independent distributors for our immunoassay products. We maintain a distribution center near Milan, Italy. +ROW +With the exception +of Australia, where we utilize a direct sales force, we utilize independent distributors throughout the rest of the world (“ROW”). +- 9 - +Table of Contents +Competition +Our major competitors in molecular diagnostics are Cepheid and Becton Dickinson, who have systems with multiple-assay menus. We also face competition in +molecular diagnostics, but to a lesser degree, from companies such as Alere and Quidel, who have a limited commercial menu and tend to compete strictly on price. We believe that our molecular platform offers a number of competitive features: +• +Molecular assay sensitivity that is comparable to higher costing PCR; +• +Low capital investment with no instrument service cost; +• +Small footprint that is portable and does not consume much laboratory space; and +• +Product menu that fits with initiatives to improve clinical and economic outcomes. +Our major competitors in +rapid immunoassay diagnostics are primarily Alere and Quidel. Over the last two years, companies such as BioMerieux have captured market share in our foodborne category via multi-plex panel tests. However, over the last several months, payors have +raised concerns over reimbursement levels relative to clinical utility. For blood lead testing, we believe we have the only FDA-cleared, CLIA-waived point-of-care test available commercially. Other blood lead testing systems in use, marketed by our competitors, include Graphite Furnace Atomic Absorption Spectroscopy, which requires a highly-skilled +technician and larger laboratory space to operate, in addition to not being portable or suitable for point-of-care use. We believe that with the breadth and depth of our +product portfolio, we are well positioned for the clinical laboratory. +Research and Development +Our Diagnostics segment’s research and development organization for infectious disease products is located at our corporate headquarters in Newtown, Ohio, +a suburb of Cincinnati, and has expertise in biochemistry, immunology, mycology, bacteriology, virology, parasitology, and molecular biology. Our Magellan business has a dedicated research and development team in Billerica, Massachusetts. Research +and development expenses for the Diagnostics segment for fiscal 2017, 2016 and 2015 were approximately $13,000, $11,000 and $10,000, respectively. Our research and development activities are focused on new product and new technology development, new +applications for our existing technologies, and improvements to existing products. Research and development efforts may occur in-house or with collaborative partners. We believe that new product development is +a key source for sustaining revenue growth. The products within our illumi gene molecular platform, H. pylori product family and blood lead testing family were developed solely +in-house, or substantially so. See “Operating Expenses” section within MD&A on page 39. +Manufacturing +Our immunoassay and molecular assay +products require the production of highly specialized reagents, primers and enzymes. We produce substantially all of our own immunoassay requirements. Primers for our illumi gene molecular assay products are purchased from +outside vendors. Our blood lead testing products require the production of electrical chemical sensors, which we manufacture using critical raw materials purchased from outside vendors. We believe that we have sufficient manufacturing and sourcing +capacity for anticipated growth over the next several years. +- 10 - +Table of Contents +Intellectual Property, Patents and Licenses +We own or license U.S. and foreign patents, most of which are for selected products manufactured by our Diagnostics segment. These patents are used in our +manufacturing processes for selected products (method patents) or may relate to the design of the test device technology format (design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully replicate our +production and manufacturing technologies and processes. Our employees are required to sign confidentiality and non-disclosure agreements designed to protect our proprietary products. +The patents for our illumi gene products, which represented 17%, 20% and 21% of consolidated revenues for fiscal 2017, 2016 and 2015, +respectively, are licensed from a third party, Eiken Chemical Co., Ltd., under a non-exclusive license agreement and expire between 2020 and 2022. These patents were issued in the U.S., European Community and +other countries. The term of our license agreement runs until the last patent expires in 2022, at which point we will be free to practice the patents without any restriction or royalty obligation. +The patents for our H. pylori products, owned by us and which represented 14%, 15% and 14% of consolidated revenues for fiscal 2017, 2016 and 2015, +respectively, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. We expect competition with respect to our H. pylori products to increase in the near future, as we currently market the only FDA-cleared tests to detect H. pylori antigen in stool samples in the U.S. market. Such competition may have an adverse impact on our selling prices for these products, or our ability to retain business at +prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to defend against competition, our product development pipeline includes multiple new product +initiatives for the detection of H. pylori , including drug resistance. We are unable to provide assurances that we will be successful with any competition defense strategy or that any competition defense strategy will prevent an adverse +effect on our future results of operations and liquidity, including revenues and gross profit. +Government Regulation +Our diagnostic products are regulated by the FDA as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (“FDCA”). Under the +FDCA, medical devices are classified into one of three classes (i.e., Class I, II or III). Class I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally +must receive “pre-market approval” from the FDA as to safety and effectiveness. Our diagnostics manufacturing facilities in Cincinnati and Billerica are subject to periodic inspection by the FDA. See +page 30 within MD&A for discussion regarding the FDA’s inspection of our Billerica facility. +- 11 - +Table of Contents +Each of the diagnostic products currently marketed by us in the United States has been cleared by the FDA +pursuant to the 510(k) clearance process or is exempt from such requirements. We believe that most, but not all, products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all +Class II devices, will be eligible for 510(k) clearance; however, we can make no assurances in this regard. +Sales of our diagnostic products in +foreign countries are subject to foreign government regulation, which is similar to that of the FDA. +Our Cincinnati manufacturing facility is certified +to ISO 13485:2012, and our Magellan facility in Billerica, Massachusetts is certified to ISO 13485:2003. +Medical Device Tax +As more fully discussed in the accompanying MD&A, the Company was subject to the medical device tax established as part of the U.S. health care reform +legislation through December 31, 2015. Upon expiration of the tax’s two-year moratorium, which is currently scheduled for December 31, 2017, the Company would become subject to the tax once +again. We are unable to predict any future legislative changes or developments related to this moratorium or excise tax. +Seasonal Factors and +Sporadic Outbreaks +Our principal business is the sale of a broad range of clinical diagnostic test kits for common gastrointestinal, viral, upper +respiratory and parasitic infectious diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as the H1N1 +influenza outbreak during fiscal 2009. While we believe that the breadth of our diagnostic product lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can +make no assurance that revenues will not be impacted period over period by such factors. +Life Science Segment +Overview of Products and Markets +Our Life Science +segment focuses on the development, manufacture, sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers, agri-bio +companies and other diagnostic manufacturing companies. Third-party revenues for this segment were approximately $57,000, $51,000 and $49,000 for fiscal 2017, 2016 and 2015, respectively. As of September 30, 2017, our Life Science segment had +approximately 220 employees in seven countries. +- 12 - +Table of Contents +Most of the revenues for our Life Science segment currently come from the manufacture, sale and distribution of +bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells and bioresearch reagents used by researchers and other diagnostic manufacturing companies focused on the development of immunoassay and molecular assay tests. Approximately +72% of Life Science revenues are generated from the industrial market, defined as diagnostic manufacturers and the agriculture industry. This continues to be an increasing focus of our Bioline molecular components business, which historically +focused on the academic/research market that comprises the remaining 28% of Life Science revenues. We utilize direct sales teams in key countries such as the U.S., the U.K., Germany, France, Australia and Singapore. We have added distribution +capabilities to our Singapore sales and business development office to increase our presence and our revenue opportunities in Asia for both molecular and immunoassay components. Additionally, in order to further pursue revenue opportunities in Asia, +and China in particular, during fiscal 2017 we established a wholly foreign owned enterprise (“WFOE”) location in Beijing, China, after having operated a representative office there since fiscal 2015. The WFOE employs a business +development staff and imports product for sales to customers in China. We utilize a network of distributors in other major countries. During fiscal 2017, 17% of third-party revenues for this segment were from two diagnostic manufacturing customers. +Products such as antibodies, antigens and reagents are marketed primarily to diagnostic manufacturing customers as a source of raw materials for their +immunoassay products, or as an outsourced step in their manufacturing processes. For example, we supply a number of major diagnostic manufacturers with proteins used to detect hepatitis A virus and rubella virus. These products are typically sold in +bulk quantities, and may also be custom-designed for a particular manufacturer’s requirements. Sales efforts are focused on multi-year supply arrangements in order to provide stability in volumes and pricing. We believe this benefits both us +and our customers. +Molecular biology products such as PCR/qPCR reagents, nucleotides and competent cells are marketed to academic/research and industrial +customers. These products are used in measuring DNA and RNA in clinical and agricultural applications. These reagents improve the purity, yield and speed of PCR reactions. Products such as MyTaq and SensiFAST are examples of this type of PCR/qPCR +reagent. +Market Trends +As certain global +markets become increasingly accessible to us, most notably the Asia-Pacific region, geographic expansion continues to be a significant strategy for our Life Science segment, along with further penetration into industrial markets with our molecular +component products. +Competition +The market +for bulk biomedical reagents is highly competitive. Important competitive factors include product quality, price, customer service and reputation. We face competitors, many of which have greater financial, research and development, sales and +marketing, and manufacturing resources, and where sole-source supply arrangements do not exist. Customers also may choose to manufacture their biomedical reagents in-house rather than purchase from outside +vendors such as Meridian. +- 13 - +Table of Contents +The academic/research market is highly fragmented. Individual purchases are typically of small quantities. The +breadth of product offerings, quality, price and service, including on-line capabilities and technical resources, are important factors to building customer loyalty and repeat purchases. +Research and Development +Research and development +expenses for our Life Science segment for each of fiscal 2017, 2016 and 2015 were approximately $3,000. The primary focus of this research and development organization is development of new molecular reagent products. See “Operating +Expenses” section within MD&A on page 39. +Manufacturing and Government Regulation +Our Life Science U.S. facilities are ISO 9001:2008 certified and our Bioline facilities in the U.K. and Germany are ISO 13485:2012 certified. Additionally, +where appropriate, our Life Science facilities comply with Regulation EC 1069:2009. +Acquisitions +Acquisitions have played an important role in the growth of our businesses. Our acquisition objectives include, among other things: (i) enhancing product +offerings; (ii) improving product distribution capabilities; (iii) providing access to new markets; and/or (iv) providing access to key biologicals or new technologies that lead to new products. Although we cannot provide assurance +that we will consummate additional acquisitions in the future, nor can we provide assurance that any acquisitions will accomplish these objectives, we expect that the potential for acquisitions will continue to provide opportunities for revenue and +earnings growth in the future. +As previously noted in the Overview section, during March 2016, we acquired all of the outstanding common stock of +Magellan. Details of the Magellan acquisition are set forth in Note 2 of the accompanying Consolidated Financial Statements. +International Markets +International markets are an important source of revenues and future growth opportunities for both of our segments. For both segments combined, +revenues from customers located outside of the Americas approximated $59,000 or 29% of consolidated fiscal 2017 revenues, $52,000 or 26% of consolidated fiscal 2016 revenues, and $49,000 or 25% of consolidated fiscal 2015 revenues. We expect to +continue to look to international markets as a source of revenue growth in the future. +- 14 - +Table of Contents +Fluctuations in foreign currency exchange rates since fiscal 2016 had an approximate $1,200 unfavorable impact on +fiscal 2017 revenues; $400 within the Diagnostics segment and $800 within the Life Science segment. This compares to year-to-year currency exchange rates having an +approximate $1,700 unfavorable impact on revenues in fiscal 2016; $700 within the Diagnostics segment and $1,000 within the Life Science segment. Due to natural hedge relationships with expenses, both cost of sales and operating expenses, the +overall impact of exchange rate fluctuations on operating income was not significant during fiscal 2017, 2016 or 2015. +Environmental +We are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. +ITEM 1A. +RISK FACTORS +In addition to the other +information set forth in this report, you should carefully consider the following factors, which could materially affect our business, financial condition, cash flows or future results. Any one of these factors could cause our actual results to vary +materially from recent results or from anticipated future results. The risks described below are not the only risks facing our company. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also +may materially adversely affect our business, financial condition and/or operating results. +Risks Affecting Growth and Profitability of our Business +We may be unable to develop new products and services or acquire products and services on favorable terms. +The medical diagnostic and life science industries are characterized by ongoing technological developments and changing customer requirements. As such, our +results of operations and continued growth depend, in part, on our ability in a timely manner to develop or acquire rights to, and successfully introduce into the marketplace, enhancements of existing products and services, or new products and +services that incorporate technological advances, meet customer requirements and/or respond to products developed by our competition. We cannot provide any assurance that we will be successful in developing or acquiring such rights to products and +services on a timely basis, or that such products and services will adequately address the changing needs of the marketplace, either of which could adversely affect our results of operations. +In addition, we must regularly allocate considerable resources to research and development of new products, services and technologies. The research and +development process generally takes a significant amount of time from research to product launch. This process is conducted in various stages. During each stage, there is a risk that we will not achieve our goals on a timely basis, or at all, and we +may have to abandon a product in which we have invested substantial resources. +- 15 - +Table of Contents +We may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions +we make. +One of our growth strategies is the acquisition of companies and/or products. Although additional acquisitions of companies and products +may enhance the opportunity to increase net earnings over time, such acquisitions could result in greater administrative burdens, increased exposure to the uncertainties inherent in marketing new products, financial risks of additional operating +costs, and risk of asset impairments if future revenues and cash flows are deficient. The principal benefits expected to result from any acquisitions we make will not be achieved fully unless we are able to successfully integrate the operations of +the acquired entities with our operations and realize the anticipated synergies, cost savings and growth opportunities from integrating these businesses into our existing businesses. We cannot provide assurance that we will be able to identify and +complete additional acquisitions on terms we consider favorable or that, if completed, will be successfully integrated into our operations. Furthermore, we cannot predict the outcome of goodwill impairment testing and the impact of goodwill +impairments on the Company’s earnings and financial results. +Revenues for our Diagnostics segment may be impacted by our reliance upon two key +distributors in North America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +Key Distributors +Our Diagnostics segment’s revenues from sales through two U.S. distributors were 29% and 27%, respectively, of the Diagnostics segment’s total +revenues, or 21% and 20%, respectively, of our consolidated revenues, for fiscal 2017 and fiscal 2016. These parties distribute our products and other laboratory products to end-user customers. The loss of +either of these distributors could negatively impact our revenues and results of operations unless suitable alternatives were timely found or lost sales to one distributor were absorbed by another distributor. Finding a suitable alternative on +satisfactory terms may pose challenges in our industry’s competitive environment. As an alternative, we could expand our efforts to distribute and market our products directly. This alternative, however, would require substantial investment in +additional sales, marketing and logistics resources, including hiring additional sales and customer service personnel, which would significantly increase our future selling, general and administrative expenses. +In addition, buying patterns of these two distributors may fluctuate from quarter to quarter, potentially leading to uneven concentration levels on a +quarterly basis. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal, viral, upper respiratory and parasitic infectious +diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as H1N1 influenza. While we believe that the +breadth of our diagnostic product lines reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in diagnostic revenues, we can make no assurance that revenues will not be negatively impacted +period over period by such factors. +- 16 - +Table of Contents +Changing Diagnostic Market Conditions +Changes in the U.S. health care delivery system have resulted in consolidation among reference laboratories, hospital laboratories being operated by large +reference laboratories, and the formation of multi-hospital alliances, reducing the number of institutional customers for diagnostic test products. Consolidation in the U.S. health care industry has also led to the creation of group purchasing +organizations (“GPOs”) and integrated delivery networks (“IDNs”) that aggregate buying power for hospital groups and put pressure on our selling prices. Due to such consolidation, we may not be able to enter into and/or sustain +contractual or other marketing or distribution arrangements on a satisfactory commercial basis with institutional customers, GPOs and IDNs, which could adversely affect our results of operations. +We could be adversely affected by health care reform legislation. +Third-party payers for medical products and services, including state, federal and foreign governments, are increasingly concerned about escalating health +care costs and can indirectly affect the pricing or the relative attractiveness of our products by regulating the maximum amount of reimbursement they will provide for diagnostic testing services. Following years of increasing pressure, during 2010 +the U.S. government enacted comprehensive health care reform with the enactment of the Patient Protection and Affordable Care Act, as amended by the Health Care and Education Reconciliation Act, which makes changes that are expected to significantly +impact the pharmaceutical and medical device industries. The Protecting Access to Medicare Act of 2014 will require applicable laboratories to report all private payor reimbursement rates and the volumes for each test they perform. Although a final +rule has yet to be published, the statute requires that Medicare establish reimbursement rates based on the weighted median of private insurance reimbursement rates effective January 1, 2017. The new Medicare rates would be subject to a maximum +reduction of 10% a year for the initial three year period and a maximum of 15% a year for the subsequent three year period. There is no limit on the amount of potential rate increases. As a result, some of our customers in the United States may +experience lower Medicare reimbursement rates for our products, which may adversely affect our business, financial condition and results of operations. Although to date, we have not seen any significant effect on the reimbursement rates for our +products, if reimbursement amounts for diagnostic testing services are decreased in the future, such decreases may reduce the amount that will be reimbursed to hospitals or physicians for such services and consequently, could place constraints on +the levels of overall pricing, which could have a material effect on our revenues and/or results of operations. +In addition, as more fully discussed in +the accompanying MD&A, the Company was subject to a 2.3% medical device tax established as part of the U.S. health care reform legislation through December 31, 2015. Upon expiration of the tax’s +two-year moratorium, which is currently scheduled for December 31, 2017, the Company would become subject to the tax once again. We are unable to predict any future legislative changes or developments +related to this moratorium or excise tax. +- 17 - +Table of Contents +Additional state and federal health care reform measures may be adopted in the future, any of which could have a +material adverse effect on our ability to successfully commercialize our products and on our industry in general. For example, the United States government has in the past considered, is currently considering and may in the future consider, health +care policies and proposals intended to curb rising health care costs, including those that could significantly affect both private and public reimbursement for health care services. Further, state and local governments, as well as a number of +foreign governments, are also considering or have adopted similar types of policies. Future significant changes in the health care system in the United States or elsewhere, and current uncertainty about whether and how changes may be implemented, +could have a negative impact on the demand for our products. We are unable to predict whether health care policies, including policies stemming from legislation or regulations affecting our business, may be proposed or enacted in the future, what +effect such policies would have on our business, or the effect that ongoing uncertainty about these matters will have on the purchasing decisions of our customers. +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +As part of the Budget Control Act passed in August 2011 to extend the federal debt limit and reduce government spending, $1.2 trillion in automatic spending +cuts (known as sequestration) were implemented in 2013. The sequestration requires a 2% cut in Medicare payments for all services, including our diagnostic tests, which, due to subsequent legislative amendments to the statute, will remain in effect +through 2024 unless Congressional action is otherwise taken. Government research funding has also been reduced as a result of the sequestration. On January 2, 2013, the American Taxpayer Relief Act of 2012 also was signed into law, which, among +other things, further reduces Medicare payments to providers such as hospitals, imaging centers and cancer treatment centers, and increases the statute of limitations period for the government to recover overpayments to providers from three to five +years. +Such reductions in government health care spending or research funding could result in reduced demand for our products or additional pricing +pressure. Further, there is ongoing uncertainty regarding the federal budget and federal spending levels, including the possible impacts of a failure to increase the “debt ceiling.” Any U.S. government default on its debt could have broad +macroeconomic effects that could, among other things, raise our borrowing costs. Any future shutdown of the federal government or failure to enact annual appropriations could also have a material adverse impact on our business. +Revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +Our Life Science segment’s revenues from sales of purified antigens and reagents to two diagnostic manufacturing customers were 17% and 18% of the Life +Science segment’s total revenues for fiscal 2017 and fiscal 2016, respectively; and 5% of our consolidated revenues for each of fiscal 2017 and fiscal 2016. Our Life Science segment has five other significant customers who purchase antigens, +antibodies and reagents, which together comprised 10% and 7% of the segment’s total revenues for fiscal 2017 and fiscal 2016, respectively. Any significant alteration of buying patterns from these customers could adversely affect our period +over period revenues and results of operations. +- 18 - +Table of Contents +Intense competition could adversely affect our profitability. +The markets for our products and services are characterized by substantial competition and rapid change. Hundreds of companies around the world supply +diagnostic tests and immunoassay and molecular reagents. These companies range from multinational health care entities, for which diagnostics is one line of business, to small start-up companies. Many of our +competitors have significantly greater financial, technical, manufacturing and marketing resources than we do. We cannot provide assurance that our products and services will be able to compete successfully with the products and services of our +competitors. +We expect to face increased competition resulting from expiration of our H. pylori patents. +The patents for our H. pylori products, owned by us, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. We expect +competition with respect to our H. pylori products to increase in the near future, as we currently market the only FDA-cleared tests to detect H. pylori antigen in stool samples in the U.S. +market. At present, we are aware of two companies that have commenced clinical trials of H. pylori products in the U.S., one of which is DiaSorin Inc. (see Item 3. “Legal Proceedings”). Such competition may have an adverse impact on +our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including revenues and gross profit. In order to mitigate any +loss in revenues, among other things, we are researching and experimenting with new products and attempting to secure significant customers under long-term contracts. We are unable to provide assurances that we will be successful with any mitigation +strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and gross profit. +See Item 3. “Legal Proceedings” for a discussion of the status of certain litigation related to our intellectual property. +We depend on international revenues, and our financial results may be adversely impacted by foreign currency, regulatory or other developments affecting +international markets. +We sell products and services into approximately 70 countries. Approximately 29% and 26% of our net revenues for fiscal +2017 and 2016, respectively, were attributable to markets outside of the Americas. For fiscal 2017, approximately 15% of our consolidated revenues were transacted in currencies other than the U.S. dollar. We are subject to the risks associated with +fluctuations in the exchange rates for the Australian dollar, British pound, Chinese yuan, Euro and Singapore dollar to the U.S. dollar. We are also subject to other risks associated with international operations, including longer customer payment +cycles, tariff regulations, requirements for export licenses, instability of foreign governments, and governmental requirements with respect to the importation and distribution of medical devices and immunodiagnostic and molecular biology reagents, +all of which may vary by country. +- 19 - +Table of Contents +Risks Affecting our Manufacturing Operations +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +Medical device diagnostics is a highly regulated industry. We cannot provide assurance that we will be able to obtain necessary governmental clearances or +approvals, or timely clearances or approvals, to market future products in the United States and other countries. Costs and difficulties in complying with laws and regulations administered by the U.S. Food and Drug Administration, the U.S. +Department of Agriculture, the U.S. Department of Commerce, the U.S. Drug Enforcement Agency, the Centers for Disease Control or other regulators can result in unanticipated expenses and delays, and interruptions to the sale of new and existing +products. +Regulatory approval can be a lengthy, expensive and uncertain process, making the timing and costs of approvals difficult to predict. The +failure to comply with these regulations can result in delays in obtaining authorization to sell products, seizure or recall of products, suspension or revocation of authority to manufacture or sell products, and other civil or criminal sanctions. +If we or our third-party vendors fail to comply with FDA regulations relating to the manufacturing of our products or any component part, we may be +subject to fines, injunctions and penalties, and our ability to commercially distribute and sell our products may be negatively impacted. +Our +diagnostics manufacturing facilities, and the manufacturing facilities of any of our third-party diagnostic component manufacturers or critical suppliers, are required to comply with the FDA’s Quality System Regulation (“QSR”) which +sets forth minimum standards for the procedures, execution and documentation of the design, testing, production, control, quality assurance, labeling, packaging, sterilization, storage and shipping of the products we sell. The FDA may evaluate our +compliance with the QSR, among other ways, through periodic announced or unannounced inspections which could disrupt our operations and interrupt our manufacturing. If in conducting an inspection of our manufacturing facilities, or the +manufacturing facilities of any of our third-party component manufacturers or critical suppliers, an FDA investigator observes conditions or practices believed to violate the QSR, the investigator may document their observations on a Form FDA 483 +that is issued at the conclusion of the inspection. A manufacturer that receives an FDA 483 may respond in writing and explain any corrective actions taken in response to the inspectional observations. The FDA will typically review the +facility’s written response and may re-inspect to determine the facility’s compliance with the QSR and other applicable regulatory requirements. Failure to take adequate and timely corrective actions +to remedy objectionable conditions listed on an FDA 483 could result in the FDA taking administrative or enforcement actions. Among these may be the FDA’s issuance of a Warning Letter to a manufacturer, which informs it that the FDA considers +the observed violations to be of “regulatory significance” that, if not corrected, could result in further enforcement action. +- 20 - +Table of Contents +FDA enforcement actions, which include seizure, injunction and criminal prosecution, could result in total or +partial suspension of a facility’s production and/or distribution, product recalls, fines, suspension of the FDA’s review of product applications, and/or the FDA’s issuance of adverse publicity. Thus, an adverse inspection could force +a shutdown of our manufacturing operations or a recall of our products. Adverse inspections could also delay FDA approval of our products and could have an adverse effect on our production, sales and profitability. +We and any of our third-party vendors may also encounter other problems during manufacturing including failure to follow specific protocols and procedures, +equipment malfunction, and environmental factors, any of which could delay or impede our ability to meet demand. The manufacture of our product also subjects us to risks that could harm our business, including problems relating to our facilities and +errors in manufacturing components that could negatively affect the efficacy or safety of our products or cause delays in shipment of our products. Any interruption or delay in the manufacture of the product or any of its components could impair our +ability to meet the demand of our customers and cause them to cancel orders or switch to competitive products, which could, therefore, have a material adverse effect on our business, financial condition and results of operations. +On June 29, 2017, the FDA, in connection with its recent Safety Notification related to Magellan’s lead testing systems for venous blood samples, +issued its Form FDA 483 to Magellan. This was followed by the FDA issuing a Warning Letter related to the matter on October 23, 2017. While we remain committed to strengthening Magellan’s quality system and ensuring that all aspects of the +system are in full compliance, we can provide no assurance that our remediation efforts will be successful to a degree acceptable by the FDA. See a more detailed discussion of this matter within MD&A on page 30. +Significant interruptions in production at our principal manufacturing facilities and/or third-party manufacturing facilities would adversely affect our +business and operating results. +Products and services manufactured at facilities we own or lease comprised a majority of our revenues. Our global +supply of these products and services is dependent on the uninterrupted and efficient operation of these facilities. In addition, we currently rely on a small number of third-party manufacturers to produce certain of our diagnostic products and +product components. The operations of our facilities or these third-party manufacturing facilities could be adversely affected by power failures, or natural or other disasters, such as earthquakes, floods, tornadoes or terrorist threats. Although we +carry insurance to protect against certain business interruptions at our facilities, there can be no assurance that such coverage will be adequate or that such coverage will continue to remain available on acceptable terms, if at all. Any +significant interruption in the Company’s or a third-party supplier’s manufacturing capabilities could materially and adversely affect our operating results. +- 21 - +Table of Contents +We depend on sole-source suppliers for certain critical raw materials, components and finished products. A +supply interruption could adversely affect our business. +Raw Materials and Components +Our diagnostic products are made from a wide variety of raw materials that are biological or chemical in nature, and that generally are available from multiple +sources of supply. We sole-source certain raw materials and components, which make it time consuming and costly to switch raw materials and components in FDA-cleared products. If certain suppliers fail to +supply required raw materials or components, we will need to secure other sources which may require us to conduct additional development and testing and obtain regulatory approval. These activities require significant time and resources, and there +is no assurance that new sources will be secured or regulatory approvals, if necessary, will be obtained. +We utilize third-party manufacturers for our +instrumentation. One third party manufactures our proprietary illumi pro-10 Incubator/Reader (instrument), a component of our illumi gene molecular system, and a +separate third party manufactures our proprietary LeadCare instruments. These instruments are manufactured exclusively for Meridian according to our specifications. While other manufacturers for these types of instruments are available, we source +solely from one manufacturer to limit the costs involved in clearing the system for marketing in the United States. If these third-party manufacturers fail to supply us with instruments, we will need to secure another manufacturer, and it may take +as long as 12 months to transfer instrument manufacturing. An interruption in the manufacturing of these instruments could have a material adverse effect on our operating results. +Additionally, one third party manufactures a certain reagent for use with our illumi gene assays. While alternative suppliers exist, we +elect to utilize this third party exclusively in order to maintain consistency in our materials, which is critical in complying with FDA regulatory requirements. An interruption in the manufacturing of these reagents could have a material adverse +effect on our operating results. +Finished Products +We outsource the manufacturing for certain finished diagnostic products to third parties. A disruption in the supply of these finished products could have a +material adverse effect on our business until we find another supplier or bring manufacturing in-house. +Four products manufactured exclusively for us by two separate and independent companies accounted for 11%, 12% and 15% of consolidated revenues in fiscal +2017, 2016 and 2015, respectively. Meridian owns all rights and title to the FDA 510(k) clearances for these products. +- 22 - +Table of Contents +Activities undertaken by Meridian to reduce the risk of these sole-supplier arrangements include maintaining +adequate inventory levels, supplier qualification procedures, supplier audits, site visits and frequent communication. Additionally, we have identified potential alternate suppliers. +Risks Related to Intellectual Property and Product Liability +We may be unable to protect or obtain proprietary rights that we utilize or intend to utilize. +In developing and manufacturing our products, we employ a variety of proprietary and patented technologies. In addition, we have licensed, and expect to +continue to license, various complementary technologies and methods from academic institutions and public and private companies. We cannot provide assurance that the technologies that we own or license provide protection from competitive threats or +from challenges to our intellectual property. In addition, we cannot provide assurances that we will be successful in obtaining and retaining licenses or proprietary or patented technologies in the future. +See Item 3. “Legal Proceedings” for a discussion of the status of certain litigation related to our intellectual property. +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Litigation over intellectual property rights is prevalent in the diagnostic industry. As the market for diagnostics continues to grow and the number of +participants in the market increases, we may increasingly be subject to patent infringement claims. It is possible that a third party may claim infringement against us. If found to infringe, we may attempt to obtain a license to such intellectual +property; however, we may be unable to do so on favorable terms, or at all. Additionally, if our products are found to infringe on third-party intellectual property, we may be required to pay damages for past infringement and lose the ability to +sell certain products, causing our revenues to decrease. Any substantial loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse +effect on our business. +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and may have to +limit or cease sales of our products. +The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of +product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We currently carry product liability insurance at a +level we believe is commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. In certain customer contracts, we indemnify third parties for certain product liability claims related to our +products. These indemnification obligations may cause us to pay significant sums of money for claims that are covered by these indemnifications. In addition, a defect in the design or manufacture of our products could have a material adverse effect +on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our +reputation in the industry could have a material adverse effect on our business. +- 23 - +Table of Contents +Other Risks Affecting Our Business +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +Our future success depends on our continued ability to attract, hire and retain highly qualified personnel, including our executive officers and scientific, +technical, sales and marketing employees, and their ability to manage growth successfully. If such key employees were to leave and we were unable to obtain adequate replacements, our operating results could be adversely affected. +Our bank credit agreements impose restrictions with respect to our operations. +Our bank credit agreements contain a number of financial covenants that require us to meet certain financial ratios and tests. If we fail to comply with the +obligations in the credit agreements, we would be in default under the credit agreements. If an event of default is not cured or waived, it could result in acceleration of any indebtedness under our credit agreements, which could have a material +adverse effect on our business. At September 30, 2017, we have approximately $55,000 outstanding on a five-year term loan entered into in connection with the Magellan acquisition and no borrowings are outstanding under our $30,000 bank +revolving credit facility. +We face risks related to global economic conditions. +We currently generate significant operating cash flows, which combined with access to the credit markets, provides us with discretionary funding capacity for +research and development and other strategic activities. However, as an enterprise with global operations and markets, our operations and financial performance are in part dependent upon global economic conditions, and we could be negatively +impacted by a global, regional or national economic crisis, including sovereign risk in the event of deterioration in the credit worthiness of or a default by local governments. We are particularly susceptible to the economic conditions in countries +where government-sponsored health care systems are the primary payers for health care, including those countries within the European Union that are reducing their public expenditures in an effort to achieve cost savings. The uncertainty in global +economic conditions poses a risk to the overall economy that could impact demand for our products, as well as our ability to manage normal commercial relationships with our customers, suppliers and creditors, including financial institutions. As +such, if global economic conditions deteriorate significantly, our business could be negatively impacted, including such areas as reduced demand for our products from a slow-down in the general economy, supplier or customer disruptions resulting +from tighter credit markets, and/or temporary interruptions in our ability to conduct day-to-day transactions through our financial intermediaries involving the payment +to or collection of funds from our customers, vendors and suppliers. While to-date such factors have not had a significant negative impact on our results or operations, we continue to monitor and plan for the +potential impact of these global economic factors. +- 24 - +Table of Contents +Following its June 23, 2016 vote to leave the European Union (commonly referred to as “Brexit”), +on March 29, 2017, the United Kingdom invoked Article 50 of the Lisbon Treaty; thus formally commencing the process of exiting the European Union. While the impact of Brexit remains uncertain, the resulting immediate changes in foreign currency +exchange rates have had a limited overall impact due to natural hedging. However, any predicted deterioration in the United Kingdom and European economic outlook may have an adverse effect on revenue growth, but the extent of such effect cannot yet +be quantified. In the longer term, it is possible that we will be directly impacted in a number of key areas including the hiring and retention of qualified staff, regulatory affairs, manufacturing and logistics. We are closely monitoring the Brexit +developments in order to determine, quantify and proactively address changes as they become clear. Despite the Brexit developments, we do not expect macroeconomic conditions to have a significant impact on our liquidity needs, financial condition or +results of operations, although no assurances can be made in this regard. We intend to continue to fund our working capital requirements and dividends from current cash flows from operating activities and cash on hand. If needed, we also have an +additional source of liquidity through our $30,000 bank revolving credit facility. Our liquidity needs may change if overall economic conditions worsen and/or liquidity and credit within the financial markets tightens for an extended period of time, +and such conditions impact the collectibility of our customer accounts receivable or impact credit terms with our vendors, or disrupt the supply of raw materials and services. +Breaches of our information technology systems could have a material adverse effect on our operations. +We rely on information technology systems to process, transmit and store electronic information in our day-to-day operations. The secure processing, maintenance and transmission of this information is critical to our operations. Like many multinational corporations, our information technology systems may be +subjected to computer viruses or other malicious codes, unauthorized access attempts, and cyber- or phishing-attacks. We also store certain information with third parties that could be subject to these types of attacks. Any such breach could +compromise our networks, and the information stored therein could be accessed, publicly disclosed, lost or stolen. Such attacks could result in our intellectual property and other confidential information being lost or stolen, disruption of our +operations, and other negative consequences, such as increased costs for security measures or remediation costs, and diversion of management attention. Any such access, disclosure or other loss of information could result in legal claims or +proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation and/or cause a loss of confidence in our products and services, all of which could +adversely affect our business revenues and competitive position. While we will continue to implement additional protective measures to reduce the risk of and detect cyber incidents, cyber-attacks are becoming more sophisticated and frequent, and the +techniques used in such attacks change rapidly. There can be no assurances that our protective measures will prevent attacks that could have a significant impact on our business. +- 25 - +Table of Contents +Natural disasters, war and other events could adversely affect our future revenues and operating income. +Natural disasters (including pandemics), war, terrorism, labor disruptions and international conflicts, and actions taken by the United States +and other governments or by our customers or suppliers in response to such events, could cause significant economic disruption and political and social instability in the United States and in areas outside of the United States in which we operate. +These events could result in decreased demand for our products, adversely affect our manufacturing and distribution capabilities, or increase the costs for, or cause interruptions in, the supply of materials from our suppliers. +Risks Related to Our Common Stock +We have identified a material weakness in our internal control over financial reporting that, if not properly corrected, could +materially adversely affect our operations and result in material misstatements in our financial statements. +As described in “Item 9A. +Controls and Procedures,” we have concluded that our internal control over financial reporting was ineffective as of September 30, 2017 because a material weakness existed in our internal control over financial reporting. If we are unable to +remediate our material weakness in a timely manner, we may be unable to provide holders of our securities with required financial information in a timely and reliable manner and we may incorrectly report financial information. Either of these events +could have a material adverse effect on our operations, investor, supplier and customer confidence in our reported financial information and/or the trading price of our common stock. +Additional stock issuance authorizations. +Our +board of directors has the authority to issue up to 1,000 shares of undesignated preferred stock and to determine the rights, preferences, privileges and restrictions, including voting rights, of such shares without any future vote or action by the +shareholders. The issuance of preferred stock under certain circumstances could have the effect of delaying or preventing a change in control of our company. Ohio corporation law contains provisions that may discourage takeover bids for our company +that have not been negotiated with the board of directors. Such provisions could limit the price that investors might be willing to pay in the future for shares of our common stock. In addition, sales of substantial amounts of shares in the public +market could adversely affect the market price of our common stock and our ability to raise additional capital at a price favorable to us. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +- 26 - +Table of Contents +ITEM 2. +PROPERTIES +Our corporate offices, +Diagnostics manufacturing facility, and Diagnostics research and development facility are located in five buildings totaling approximately 120,000 square feet on 10 acres of land in the Village of Newtown, a suburb of Cincinnati, Ohio. These +properties are owned by us. Magellan’s operations are headquartered in an approximately 32,000 square foot leased facility in Billerica, Massachusetts, in which it conducts manufacturing, research and development, sales, and administrative +activities. We also operate a Diagnostics sales and distribution center near Milan, Italy in an approximately 18,000 square foot building. This facility is owned by our wholly-owned Italian subsidiary, Meridian Bioscience Europe s.r.l. We also rent +office space in Paris, France and Braine-l’Alleud, Belgium for sales and administrative functions. +Our Life +Science operations are conducted in several facilities in Memphis, Tennessee; Boca Raton, Florida; Taunton, Massachusetts; London, England; Luckenwalde, Germany; Sydney, Australia; Singapore; and Beijing, China. Our facility in Memphis, Tennessee +consists of two buildings totaling approximately 44,000 square feet and is owned by us. Our leased facility in Boca Raton, Florida contains approximately 7,500 square feet of manufacturing space. Following are details of our other Life Science +facilities, all of which are leased: Taunton – approximately 10,000 square feet of sales and warehouse space; London – approximately 21,000 square feet of sales, warehouse, distribution, research and development, manufacturing and +administrative office space; Luckenwalde –approximately 10,000 square feet of sales, warehouse and manufacturing space; Sydney – approximately 5,000 square feet of sales, warehouse, research and development, and manufacturing space; +Singapore – approximately 2,000 square feet of sales and business development space; Beijing – less than 1,000 square feet of sales and business development space. +ITEM 3. +LEGAL PROCEEDINGS +We are a party to +various litigation matters that we believe are in the normal course of business. Aside from the matters discussed below, the ultimate resolution of these matters is not expected to have a material adverse effect on our financial position, results of +operations or cash flows, and no material provision has been made in the accompanying Consolidated Financial Statements for these matters. +On May 17, +2017, Meridian filed a complaint in the United States District Court for the Southern District of Ohio, Western Division (Cincinnati) naming DiaSorin Inc. (“DiaSorin”) as a defendant. Meridian’s complaint alleges DiaSorin has breached +the 2010 Co-Development and License Agreement (the “Agreement”) between it and Meridian relating to the co-development of certain tests and diagnostic products, pursuant to which Meridian disclosed certain trade secrets and proprietary +information. The lawsuit underlying Meridian’s complaint alleges +- 27 - +Table of Contents +that DiaSorin breached the Agreement and used, and is currently using, Meridian’s proprietary information and therefore seeks injunctive relief and unspecified damages to protect +Meridian’s intellectual property and information with respect to it diagnostics products. Approximately $1,500 of expense related to this matter is included within the accompanying Consolidated Statement of Operations for fiscal 2017. +On November 15, 2017, Barbara Forman filed a class action complaint in the United States District Court for the Southern District of Ohio naming Meridian, its +Chief Executive Officer and Chief Financial Officer (in their capacities as such) as defendants. The complaint alleges that Meridian made false and misleading representations concerning certain lead test systems used by Magellan at or around the +time of Meridian’s acquisition of Magellan and subsequent thereto. The lawsuit underlying plaintiff’s class action complaint seeks compensatory damages, injunctive relief and attorneys’ fees to all members of the proposed class. +Because the litigation and related discovery are in preliminary stages, we do not have sufficient information to determine or predict the ultimate outcome or estimate the range of possible losses, if any. Accordingly, no provision for litigation +losses has been included within the accompanying Consolidated Statement of Operations for fiscal 2017. +ITEM 4. +MINE SAFETY DISCLOSURES +Not +applicable. +PART II. +ITEM 5. +MARKET FOR REGISTRANT’S COMMON +EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Refer to “Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A +“Risk Factors” on Pages 15 through 26 of this Annual Report. +“Common Stock Information” on the inside back cover of the Annual +Report to Shareholders for fiscal 2017 and “Quarterly Financial Data (Unaudited)” relating to our dividends in Note 10 to the Consolidated Financial Statements are incorporated herein by reference. Except as may otherwise be prohibited by +applicable law, there are no restrictions on cash dividend payments. +Following the release of results for the fiscal 2017 first quarter, the board of +directors reduced the fiscal 2017 indicated annual cash dividend rate to $0.50 per share (down from $0.80 per share) in order to align it with the stated policy guidelines of the payout ratio to range between 75% and 85% of each fiscal year’s +net earnings. This indicated annual rate represents 75% of fiscal 2017’s non-GAAP diluted earnings per share. The declaration and amount of dividends will be determined by the board of directors in its +discretion based upon its evaluation of earnings, cash flow requirements and future business developments and opportunities, including +- 28 - +Table of Contents +acquisitions. At its meeting on November 8, 2017, the board of directors announced a continuation of the $0.50 indicated annual dividend rate per share for fiscal 2018. We paid dividends of +$0.575 per share in fiscal 2017, and $0.80 per share in each of fiscal 2016 and fiscal 2015. +As of September 30, 2017, there were approximately 675 +holders of record and approximately 15,200 beneficial owners of our common shares. +ITEM 6. +SELECTED FINANCIAL DATA +Incorporated by +reference from inside front cover of the Annual Report to Shareholders for 2017. +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Refer to “Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A +“Risk Factors” on Pages 15 through 26 of this Annual Report. +In the discussion that follows, all dollar amounts are in thousands (both +tables and text), except per share data . +Results of Operations : +Fourth Quarter +Net earnings for the fourth quarter +of fiscal 2017 increased 4% to $5,726, or $0.13 per diluted share, from net earnings for the fourth quarter of fiscal 2016 of $5,491, or $0.13 per diluted share. The fiscal 2017 fourth quarter results include $762 of costs associated with the +transition to our new CEO, announced October 10, 2017, and litigation costs associated with protecting certain intellectual property (collectively, “CEO transition and IP defense costs”) (impact on net earnings of $495, or $0.01 per +diluted share). The fiscal 2016 fourth quarter results included $677 of costs associated with the restructuring of our sales and marketing leadership (impact on net earnings of $431, or $0.01 per diluted share). Consolidated revenues for the fourth +quarter of fiscal 2017 totaled $49,697, an increase of 6% compared to the fourth quarter of fiscal 2016; increasing 5% on a constant-currency basis. +Showing positive signs of stabilization and a return to revenue growth in the Americas geographic region, revenues for the Diagnostics segment for the fourth +quarter of fiscal 2017 increased 3% compared to the fourth quarter of fiscal 2016 (increasing 2% on a constant-currency basis), comprised of a 5% decrease in molecular assay products and a 6% increase in immunoassay and point-of-care lead testing products. With a 9% increase in its molecular components business and an 18% increase in its immunoassay components business, revenues +- 29 - +Table of Contents +for our Life Science segment increased 14% in the fourth quarter of fiscal 2017 compared to the fourth quarter of fiscal 2016. On a constant-currency basis, revenues for our Life Science Segment +increased 13%. +The fourth quarter revenues reflect improvement in our immunoassay product lines, most notably in the foodborne and H. pylori +product families, being partially offset by decreased revenues in Magellan’s lead testing systems with venous blood samples. Our C. difficile business overall shows signs of stabilization and as a result, has also contributed to +stabilization in our illumi gene molecular business. Both Life Science units performed well, reflecting the strength of new products and growth in the Asia-Pacific region. +Fiscal Year +Net earnings for fiscal 2017 +decreased 33% to $21,557, or $0.51 per diluted share, from net earnings for fiscal 2016 of $32,229, or $0.76 per diluted share. Fiscal 2017 results include (i) $762 of CEO transition and IP defense costs; and (ii) a $6,628 impairment charge +against Magellan goodwill (combined impact on net earnings of $7,123, or $0.17 per diluted share). Fiscal 2016 results include $677 of costs associated with the restructuring of our sales and marketing leadership and $1,481 of costs associated with +our acquisition activities (combined impact on net earnings of $1,664, or $0.04 per diluted share). Consolidated revenues increased 2% to $200,771 for fiscal 2017 compared to fiscal 2016; increasing 3% on a constant-currency basis. +In fiscal 2017, revenues for the Diagnostics segment decreased 1% compared to fiscal 2016 (also 1% on a constant-currency basis). This decrease is comprised +of a 13% decrease in molecular assay products and a 3% increase in immunoassay and lead testing products, including an $8,027 increase in Magellan revenues resulting from only six months of Meridian ownership during the comparable fiscal 2016 +period. With an 8% increase in its molecular components business and a 15% increase in its immunoassay components business, revenues of our Life Science segment increased 12% during fiscal 2017 compared to fiscal 2016; increasing 14% on a +constant-currency basis. +Magellan FDA Activities and Goodwill Impairment Charge +On May 17, 2017, the FDA issued a field safety notice advising customers to discontinue use of Magellan’s lead testing systems with venous blood samples. +This field safety notice was followed by product recall notices on May 25 th and June 5 th . Magellan’s lead testing systems are capable of +processing both capillary and venous blood samples. Magellan’s LeadCare Plus and LeadCare Ultra systems, which account for approximately 10% of Magellan’s annual revenues, are used predominantly with venous blood samples. Magellan’s +LeadCare and LeadCare II systems are predominantly used with capillary blood samples. +Subsequent to the issuances of these field safety and product +recall notices, the FDA completed an inspection of Magellan’s quality system, and issued its Form 483, Inspectional Observations, on June 29, 2017, which was expectedly followed by a Warning Letter issued on October 23, 2017. The Warning Letter +requires periodic reporting on our remediation progress. +- 30 - +Table of Contents +As a result of these matters, we expect to experience delays in reinstating venous blood sample testing on our +LeadCare products, as well as in obtaining 510(k) clearance for new Magellan products. We also expect delays in obtaining export certifications for Magellan products during the remediation period. In light of these factors and their impacts, during +our third fiscal quarter, it was determined that a potential impairment of goodwill recorded in connection with the acquisition of Magellan had occurred (i.e., a “triggering event”). With the assistance of an independent valuation firm, +Magellan’s fair value was calculated via both market (comparable company) and income (discounted cash flows) approaches. Based upon these approaches, it was determined that the carrying value of the Magellan reporting unit did, in fact, exceed +its fair value. As a result, an impairment charge of $6,628, on both a pre-tax and after-tax basis, was recorded during the third quarter and is reflected as a separate operating expense line item within the accompanying Consolidated Statement of +Operations for the year ended September 30, 2017. Given all of the factors considered, we do not anticipate, at this time, any further goodwill impairment charge from the Magellan acquisition. +This impairment charge does not impact our cash flow, our dividend or our bank covenants. Our outlook for Magellan’s LeadCare II testing volume continues +to be healthy. In the time period since the FDA released its Safety Notification (which pertained to venous blood lead testing performed on the systems produced by Magellan), 374 new LeadCare II systems utilizing capillary blood samples have been +placed in physician offices and clinics, contributing to the total number of LeadCare II placements increasing approximately 15% during fiscal 2017. These placements and ongoing placements of LeadCare II point-of-care systems and related capillary blood testing are expected to drive revenue growth in 2018 and beyond. +The matters giving rise to the FDA Safety Notification occurred at Magellan prior to Meridian’s acquisition of Magellan. Meridian is committed to working +diligently to strengthen Magellan’s quality system and to address the observations noted in the Form FDA 483 with the highest sense of urgency. However, we can provide no assurance that our remediation efforts will be successful to a degree +acceptable by the FDA within our contemplated time frame. It should be noted that the FDA has stated that all LeadCare blood lead testing systems can be used with capillary blood samples, the predominant sample type used by physicians testing at the +point-of-care. We believe point-of-care lead testing is critical to addressing elevated +lead levels among children and adults across the globe, as testing at the point-of-care improves compliance and facilitates patient education and intervention. +Beyond the impact of the impairment charge, revenues from LeadCare Plus and Ultra, which utilize primarily venous blood samples, have decreased approximately +$200 since receipt of the May 17 th field safety notice. Remediation costs in fiscal 2017 associated with the matter were approximately $500 pre-tax, resulting in a total impact of less than $0.01 +on diluted earnings per share for the year. Remediation costs in fiscal 2018 are expected to be approximately $600 pre-tax, or less than $0.01 impact on diluted earnings per share. Remediation costs relate primarily to professional fees for +regulatory consultants and periodic quality system audits. In the +- 31 - +Table of Contents +course of remediation, Magellan may encounter additional matters that warrant notifications to the FDA and/or customers regarding the use of its products. At this time, we do not believe that any +such notifications would impact the ability to use the LeadCare systems with capillary blood samples. In addition, at this time, we do not believe that there is any further impact on our results of operations or financial condition. +USE OF NON-GAAP MEASURES +We have supplemented our reported GAAP financial information with information on net earnings, basic earnings per share and diluted earnings per share +excluding the effects of CEO transition and IP defense costs (fiscal 2017), the impairment charge against Magellan goodwill (fiscal 2017), sales & marketing leadership reorganization costs (fiscal 2016) and acquisition-related costs (fiscal +2016), each of which is a non-GAAP measure, as well as reconciliations to amounts reported under U.S. Generally Accepted Accounting Principles. We believe that this information is useful to those who read our +financial statements and evaluate our operating results because: +1. +These measures help to appropriately evaluate and compare the results of operations from period to period by removing the impacts of these non-routine items; and +2. +These measures are used by our management for various purposes, including evaluating performance against incentive bonus achievement targets, comparing performance from period to period in presentations to our board of +directors, and as a basis for strategic planning and forecasting. +These non-GAAP measures may be +different from non-GAAP measures used by other companies. In addition, these non-GAAP measures are not based on any comprehensive set of accounting rules or principles. Non-GAAP measures have limitations, in that they do not reflect all amounts associated with our results as determined in accordance with U.S. GAAP. Therefore, these measures should only be used to evaluate our +results in conjunction with corresponding GAAP measures. +2017 +2016 +2015 +Net Earnings - +U.S. GAAP basis +$ +21,557 +$ +32,229 +$ +35,540 +CEO transition and IP defense costs (1) +495 +— +— +Goodwill impairment charge (2) +6,628 +— +— +Sales & marketing leadership reorganization (1) +— +431 +— +Acquisition-related costs (1) +— +1,233 +— +Adjusted earnings +$ +28,680 +$ +33,893 +$ +35,540 +Net Earnings per Basic Common Share - +U.S. GAAP basis +$ +0.51 +$ +0.77 +$ +0.85 +CEO transition and IP defense costs (1) +0.01 +— +— +Goodwill impairment charge (2) +0.16 +— +— +Sales & marketing leadership reorganization (1) +— +0.01 +— +Acquisition-related costs (1) +— +0.03 +— +Adjusted Basic EPS +$ +0.68 +$ +0.81 +$ +0.85 +Net Earnings per Diluted Common Share - +U.S. GAAP basis +$ +0.51 +$ +0.76 +$ +0.85 +CEO transition and IP defense costs (1) +0.01 +— +— +Goodwill impairment charge (2) +0.16 +— +— +Sales & marketing leadership reorganization (1) +— +0.01 +— +Acquisition-related costs (1) +— +0.03 +— +Adjusted Diluted EPS (3) +$ +0.67 +$ +0.80 +$ +0.85 +(1) These CEO transition and IP defense costs, sales & marketing +leadership reorganization costs, and acquisition-related costs are net of income tax effects of $267, $246 and $248, respectively, which were calculated using the effective tax rates of the jurisdictions in which the costs were incurred. +(2) Since the goodwill impairment charge was not deductible for tax purposes, there are no +income tax effects. +(3) Net Earnings per Diluted Common Share for fiscal 2017 does not sum +to the total Adjusted Diluted EPS due to rounding. +- 32 - +Table of Contents +REVENUE OVERVIEW +Below are analyses of the Company’s revenue, provided for each of the following: +• +By Reportable Segment & Geographic Region +• +By Product Platform/Type +Revenue Overview- By Reportable Segment & Geographic Region +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations for infectious disease +diagnostic products in Cincinnati, Ohio and, as a result of the acquisition of Magellan, manufacturing operations for products detecting elevated lead levels in blood in Billerica, Massachusetts (near Boston). These diagnostic test products are sold +and distributed in the countries comprising North, Central and South America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, or “ROW”). +The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, +nucleotides, competent cells, and bioresearch reagents domestically and abroad, including sales, business development, and distribution facilities in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. +Revenues for the Diagnostics segment, in the normal course of business, may be affected from quarter to quarter by buying patterns of major distributors, +seasonality and the severity of seasonal diseases and outbreaks, and foreign currency exchange rates. Revenues for the Life Science segment, in the normal course of business, may be affected from quarter to quarter by buying patterns of major +customers, and foreign currency exchange rates. We believe that the overall breadth of our product lines serves to reduce the variability in consolidated revenues due to these factors. +Revenues for each of our segments and the geographic regions therein are shown below. +2017 +2016 +2015 +2017 vs. +2016 +Inc (Dec) +2016 vs. +2015 +Inc (Dec) +Diagnostics- +Americas +$ +120,589 +$ +123,714 +$ +123,366 +(3 +)% +— +% +EMEA +19,454 +18,424 +19,135 +6 +% +(4 +)% +ROW +3,478 +2,976 +3,613 +17 +% +(18 +)% +Total Diagnostics +143,521 +145,114 +146,114 +(1 +)% +(1 +)% +Life Science- +Americas +21,163 +20,651 +22,363 +2 +% +(8 +)% +EMEA +21,550 +19,406 +17,845 +11 +% +9 +% +ROW +14,537 +10,911 +8,508 +33 +% +28 +% +Total Life Science +57,250 +50,968 +48,716 +12 +% +5 +% +Consolidated +$ +200,771 +$ +196,082 +$ +194,830 +2 +% +1 +% +% of total revenues- +Diagnostics +71 +% +74 +% +75 +% +Life Science +29 +% +26 +% +25 +% +Total +100 +% +100 +% +100 +% +Ex-Americas +29 +% +26 +% +25 +% +- 33 - +Table of Contents +Revenue Overview- By Product Platform/Type +The revenues generated by each of our reportable segments result primarily from the sale of the following segment-specific categories of products: +Diagnostics +1) +Molecular assays that operate on our illumi gene platform +2) +Immunoassays and lead tests on multiple technology platforms +Life Science +1) +Molecular components +2) +Immunoassay components +Revenues for each product platform/type, as well as its relative percentage of segment +revenues, are shown below. +2017 +2016 +2015 +2017 vs. +2016 +Inc (Dec) +2016 vs. +2015 +Inc (Dec) +Diagnostics- +Molecular assays +$ +33,463 +$ +38,302 +$ +40,880 +(13 +)% +(6 +)% +Immunoassays & lead tests +110,058 +106,812 +105,234 +3 +% +1 +% +Total Diagnostics +$ +143,521 +$ +145,114 +$ +146,114 +(1 +)% +(1 +)% +Life Science- +Molecular components +$ +22,205 +$ +20,599 +$ +20,601 +8 +% +— +% +Immunoassay components +35,045 +30,369 +28,115 +15 +% +8 +% +Total Life Science +$ +57,250 +$ +50,968 +$ +48,716 +12 +% +5 +% +% of Diagnostics revenues- +Molecular assays +23 +% +26 +% +28 +% +Immunoassays & lead tests +77 +% +74 +% +72 +% +Total Diagnostics +100 +% +100 +% +100 +% +% of Life Science revenues- +Molecular components +39 +% +40 +% +42 +% +Immunoassay components +61 +% +60 +% +58 +% +Total Life Science +100 +% +100 +% +100 +% +- 34 - +Table of Contents +Following is a discussion of the revenues generated by each of these product platforms/types: +Diagnostics Products +Molecular Assay Products +During fiscal 2017, revenues from our illumi gene molecular +platform of products totaled $33,463, representing a 13% decrease from fiscal 2016 (also 13% in constant-currency). This decrease reflects the ongoing increased competition within the molecular-based testing market, most notably within the market +for C. difficile testing. +We have nearly 1,650 customer account placements. Of these account placements, approximately 1,375 accounts have +completed evaluations and validations and are regularly purchasing product, with the balance of our account placements being in some stage of product evaluation and/or validation. Of our account placements, we have nearly 600 accounts that are +regularly purchasing, evaluating and/or validating two or more assays. Increasing the number of customers utilizing two or more assays is a key objective, as we believe broader menu utilization lessens the risk of displacement by competitors. +We continue to invest in new product development for our molecular testing platform, and this platform now has nine commercialized tests spanning hospital +acquired infections, women’s health, respiratory, sexually transmitted diseases, and tropical diseases. As of September 30, 2017, our illumi gene Malaria test has been placed in nearly 150 accounts in the EMEA region +for use as a screening test for travelers returning to Europe from endemic areas in Africa. Our efforts to develop market channels in the endemic areas of Africa continue, as we work to convince policy-makers of the advantages of a more accurate +molecular test to assist in efforts to eradicate malaria. +We believe that the diagnostic testing market, particularly in the U.S., is continuing to +selectively move away from culture and immunoassay testing to molecular testing for diseases where there is a favorable cost/benefit position for the total cost of health care. During fiscal 2017 we experienced 4% growth in all +illumi gene testing categories, other than the hyper-competitive C. difficile arena, which has stabilized in recent quarters. While this market is competitive, with molecular companies such as Cepheid and Becton Dickinson, +and others such as Quidel, Nanosphere and Alere, we believe we are well-positioned. Our simple, easy-to-use, illumi gene platform, with its expanding +menu, requires no expensive equipment purchase and little to no maintenance cost. We believe these features, along with its small footprint and the performance of the illumi gene assays, make illumi gene an +attractive molecular platform for any size hospital or physician office laboratory that runs moderately-complex tests. We continue to invest in the development of additional assays for this platform and expect a test for congenital cytomegalovirus +(CMV), a leading cause of deafness in infants, to be our next FDA-cleared test on the illumi gene platform. +- 35 - +Table of Contents +Immunoassay and Lead Testing Products +Revenues from our Diagnostics segment’s immunoassay and lead testing products increased 3% in fiscal 2017, following a 1% increase in fiscal 2016. These +results reflect the current fiscal year including a full twelve months of Magellan revenue, significantly offset by decreased revenue in our H. pylori and other immunoassay product lines. +Revenues from Magellan’s sale of products to test for elevated levels of lead in blood totaled $18,061. Compared to the twelve months ended +September 30, 2016, of which the six months ended March 31, 2016 were prior to Meridian’s ownership of Magellan, these revenues increased 2%. This increase was achieved despite the effect on venous blood testing revenue of the +previously-noted FDA-related activities. +During fiscal 2017, revenues from our H. pylori products +decreased 4% (also 4% in constant-currency) to $30,948, which followed an 8% increase during fiscal 2016. In fiscal 2016, we employed bulk-buy sales programs (also referred to as +“stock-and-block” programs) intended to increase major customer inventory levels as a defense against potential competitors upon the expiration of our patent, +as further described below. We expect our H. pylori revenue to continue to return to low single-digit growth in fiscal 2018. This growth expectation reflects volume growth from the ongoing conversion of serology testing to our antigen tests. +We continue to believe there are ongoing benefits to be realized from our partnerships with managed care companies in promoting (i) the health and economic benefits of a test and treat strategy; (ii) changes in policies that discourage the +use of traditional serology methods and promote the utilization of active infection testing methods; and (iii) physician behavior movement away from serology-based testing and toward direct antigen testing. A significant amount of the H. +pylori product revenues are sales to reference labs, whose buying patterns may not be consistent from period to period. During fiscal 2017, we also introduced capabilities to identify resistance to Clarithromycin, the antibiotic commonly used to +treat H. pylori . This is currently available in an Analyte Specific Reagent (ASR) format. We believe that partnering the ability to diagnose H. pylori and identify resistance provides a strong competitive advantage. +The patents for our H. pylori products, owned by us, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. We expect +competition with respect to our H. pylori products to increase in the near future, as we currently market the only FDA-cleared tests to detect H. pylori antigen in stool samples in the U.S. +market. Such competition may have an adverse impact on our selling prices for these products, or our ability to retain business at prices acceptable to us, and consequently, adversely affect our future results of operations and liquidity, including +revenues and gross profit. In order to mitigate competition, our product development pipeline includes multiple new product initiatives for the detection of H. pylori . We are unable to provide assurances that we will be successful with any +mitigation strategy or that any mitigation strategy will prevent an adverse effect on our future results of operations and liquidity, including revenues and gross profit. See Item 3. “Legal Proceedings” for a discussion of the status of +certain litigation related to our intellectual property. +- 36 - +Table of Contents +During fiscal 2017, revenues from our other immunoassay products (including C. difficile , foodborne and +respiratory) decreased 7% (also 7% in constant-currency) to $58,732, following a 16% decrease in fiscal 2016. A return to growth during the second half of the fiscal year supports our belief that this portion of our business has stabilized and is +positioned for future growth (5% increase during the second half of the year, following a 16% decline in the first half of the year). +Life Science +Products +During fiscal 2017, revenues from our Life Science segment increased 12%, with revenues from molecular component sales increasing 8% compared +to fiscal 2016 and revenues from immunoassay component sales increasing 15%. Life Science segment revenues increased 5% in fiscal 2016, with revenues from molecular component sales remaining flat compared to fiscal 2015 and revenues from immunoassay +component sales increasing 8%. Our molecular components business’ growth was negatively impacted by the movement in currency exchange rates since fiscal 2016, with revenues increasing 12% on a constant-currency basis over fiscal 2016. During +fiscal 2017, our Life Science segment continued to benefit from (i) increased revenues in the steadily-expanding tropical disease product family, with sales of such products doubling to approximately $2,200 in fiscal 2017; and +(ii) increased revenue from sales into China, with such sales totaling approximately $5,900 during fiscal 2017 (approximately $1,000 in the molecular components business and $4,900 in the immunoassay components business) – representing an +approximate 44% increase over fiscal 2016. New products, including EPIK ™ miRNA Select, JetSeq ™ , and SensiFast ™ Lyo-Ready, also contributed to the increase, with incremental year-over-year revenue growth of approximately +$700. +Foreign Currency +Fluctuations in +foreign currency exchange rates since fiscal 2016 had an approximate $1,200 unfavorable impact on fiscal 2017 revenues; $400 within the Diagnostics segment and $800 within the Life Science segment. This compares to year-to-year currency exchange rates having an approximate $1,700 unfavorable impact on revenues in fiscal 2016; $700 within the Diagnostics segment and $1,000 within the Life Science segment. Due to natural +hedge relationships with expenses, both cost of sales and operating expenses, the overall impact of exchange rate fluctuations on net earnings was not significant during fiscal 2017, 2016 or 2015. +Significant Customers +Revenue concentrations +related to certain customers within our Diagnostics and Life Science segments are set forth in Note 8 of the accompanying Consolidated Financial Statements. +- 37 - +Table of Contents +Medical Device Tax +On January 1, 2013, the medical device tax established as part of the U.S. health care reform legislation became effective, and as a result, the Company +made its first required tax deposit near the end of January 2013. During fiscal 2017, 2016 and 2015, the Company recorded approximately $0, $500 and $1,900, respectively, of medical device tax expense, which is reflected as a component of cost of +sales in the accompanying Consolidated Statements of Operations. During December 2015, the Consolidations Appropriations Act of 2016 imposed a two-year moratorium on this excise tax effective January 1, +2016. This moratorium expires December 31, 2017, and we are unable to predict any future legislative changes or developments related to this moratorium or excise tax. +Gross Profit: +2017 +2016 +2015 +2017 vs. +2016 +Inc (Dec) +2016 vs. +2015 +Inc (Dec) +Gross Profit +$ +124,833 +$ +127,787 +$ +121,882 +(2 +)% +5 +% +Gross Profit Margin +62 +% +65 +% +63 +% +-3 points ++2 points +The overall gross profit margin decrease during fiscal 2017 primarily results from the combined effects of (i) mix of +products sold, particularly decreased contribution from our higher margin H. pylori products; (ii) customer mix; (iii) operating segment mix; and (iv) decreased production levels in certain of our production facilities designed +to reduce inventory levels. The overall increase in the gross profit margin from fiscal 2015 to fiscal 2016 reflects the combined effects of (i) mix of products sold, particularly the higher revenue contribution from H. pylori products; +(ii) realization of manufacturing facility efficiencies for our illumi gene products as a result of bringing in-house certain reagent dispensing operations that were previously +outsourced; (iii) manufacturing efficiencies in our Life Science segment; (iv) favorable effects of currency rates related to products where the purchase cost is denominated in Euros but the customer sales are billed in U.S. dollars; and +(v) decreased medical device tax payments. +Our overall operations consist of the sale of diagnostic test kits for various disease states and in +alternative test formats, as well as bioresearch reagents, bulk antigens and antibodies, PCR/qPCR reagents, nucleotides, competent cells, and proficiency panels. Product revenue mix shifts, in the normal course of business, can cause the +consolidated gross profit margin to fluctuate by several points. +- 38 - +Table of Contents +Operating Expenses : +Research & +Development +Selling & Marketing +General & +Administrative +Other +Total Operating +Expenses +Fiscal 2015: +Diagnostics +$ +9,625 +$ +17,943 +$ +19,284 +$ +— +$ +46,852 +Life Science +2,980 +7,658 +8,332 +— +18,970 +Total 2015 Expenses +$ +12,605 +$ +25,601 +$ +27,616 +$ +— +$ +65,822 +Fiscal 2016: +Diagnostics +$ +11,130 +$ +21,200 +$ +22,335 +$ +2,158 +$ +56,823 +Life Science +2,685 +8,671 +8,230 +— +19,586 +Total 2016 Expenses +$ +13,815 +$ +29,871 +$ +30,565 +$ +2,158 +$ +76,409 +Fiscal 2017: +Diagnostics +$ +13,166 +$ +22,727 +$ +24,491 +$ +7,390 +$ +67,774 +Life Science +2,514 +9,374 +7,789 +— +19,677 +Total 2017 Expenses +$ +15,680 +$ +32,101 +$ +32,280 +$ +7,390 +$ +87,451 +Research & +Development +Selling & Marketing +General & +Administrative +Other +Total Operating +Expenses +2015 Expenses +$ +12,605 +$ +25,601 +$ +27,616 +$ +— +$ +65,822 +% of Revenues +6 +% +13 +% +14 +% +— +% +34 +% +Fiscal 2016 Increases (Decreases): +Diagnostics +1,505 +3,257 +3,051 +2,158 +9,971 +Life Science +(295 +) +1,013 +(102 +) +— +616 +2016 Expenses +$ +13,815 +$ +29,871 +$ +30,565 +$ +2,158 +$ +76,409 +% of Revenues +7 +% +15 +% +16 +% +1 +% +39 +% +% Increase +10 +% +17 +% +11 +% +NMF +16 +% +Fiscal 2017 Increases (Decreases): +Diagnostics +2,036 +1,527 +2,156 +5,232 +10,951 +Life Science +(171 +) +703 +(441 +) +— +91 +2017 Expenses +$ +15,680 +$ +32,101 +$ +32,280 +$ +7,390 +$ +87,451 +% of Revenues +8 +% +16 +% +16 +% +4 +% +44 +% +% Increase +13 +% +7 +% +6 +% +242 +% +14 +% +- 39 - +Table of Contents +Total operating expenses increased during both fiscal 2017 and fiscal 2016, resulting primarily from the combined +effects of the following: +Diagnostics +Fiscal 2017 increase +• +Magellan goodwill impairment charge; +• +Incremental Magellan operating expenses due to six additional months of Meridian ownership in fiscal 2017; +• +Increased R&D costs in connection with instrumentation development programs, with such elevated level of spending expected to continue into fiscal 2018 as the programs are completed and transitioned to clinical +trials; and +• +CEO transition and IP defense costs. +Fiscal 2016 increase +• +Addition of Magellan’s operating expenses since the March 24, 2016 date of acquisition, which represent approximately 50% of the total Diagnostics operating expense increase; +• +Increased investment in Sales & Marketing activities, including new leadership and an expansion in sales territories; +• +Costs incurred in connection with acquisition activities, most notably related to the acquisition of Magellan; and +• +Costs incurred in connection with restructuring Sales & Marketing leadership, which relate to severance obligations for former employees. +Life Science +Fiscal 2017 +increase +• +Increased investment in Sales & Marketing activities, including costs associated with the WFOE established in Beijing, China during fiscal 2017. +Fiscal 2016 increase +• +Increased investment in Sales & Marketing activities, including increased personnel, travel and marketing spending. +The amount of stock-based compensation expense reported for fiscal 2017, 2016 and 2015 was $3,381, $2,911 and $3,324, respectively. Details of the stock-based +compensation activities giving rise to these expenses are set forth in Note 6 of the accompanying Consolidated Financial Statements. +- 40 - +Table of Contents +Operating Income +Operating income decreased 27% and 8% in fiscal 2017 and 2016, respectively, as a result of the factors discussed above, including the Magellan goodwill +impairment charge and CEO transition and IP defense costs in fiscal 2017 and the costs associated with acquisition-related activities and sales & marketing leadership reorganization in fiscal 2016. +Other Income and Expense +Other income and expense in +fiscal 2017 and fiscal 2016 includes interest costs on the term loan used to fund the acquisition of Magellan. The effective interest rate on this term loan is 2.76%. In fiscal 2015, other income and expense included $1,100 of foreign currency +losses, which related primarily to a foreign subsidiary intercompany loan. This compares to $400 and $600 of foreign currency gains in fiscal 2017 and fiscal 2016, respectively. +Income Taxes +The effective rate for income taxes was +41%, 36% and 35% for fiscal 2017, 2016 and 2015, respectively. The increased fiscal 2017 rate results primarily from the non-deductibility of the Magellan goodwill impairment charge. Excluding the effects of +the Magellan goodwill impairment charge, the effective tax rate was 35% for fiscal 2017. +Impact of Inflation +To the extent feasible, we have consistently followed the practice of adjusting our prices to reflect the impact of inflation on salaries and fringe benefits +for employees and the cost of purchased materials and services. Inflation and changing prices did not have a material adverse impact on our gross margin, revenues or operating income in fiscal 2017, 2016 or 2015. +Liquidity and Capital Resources: +Liquidity +Our cash flow and financing requirements are determined by analyses of operating and capital spending budgets, debt service, consideration of +acquisition plans and consideration of common share dividends. We have historically maintained a credit facility to augment working capital requirements and to respond quickly to acquisition opportunities. +- 41 - +Table of Contents +We have an investment policy that guides the holdings of our investment portfolio, which presently consists of +overnight repurchase agreements, bank savings accounts and institutional money market mutual funds. Our objectives in managing the investment portfolio are to (i) preserve capital; (ii) provide sufficient liquidity to meet working capital +requirements and fund strategic objectives such as acquisitions; and (iii) capture a market rate of return commensurate with market conditions and our policy’s investment eligibility criteria. As we look forward, we will continue to manage +the holdings of our investment portfolio with preservation of capital being the primary objective. +Considering the various worldwide geo-political and geo-economic conditions (including Brexit, as more fully discussed within the “Risk Factors” section of Part 1A), we do not expect macroeconomic +conditions to have a significant impact on our liquidity needs, financial condition or results of operations, although no assurances can be made in this regard. We intend to continue to fund our working capital requirements and dividends from +current cash flows from operating activities and cash on hand. If needed, we also have an additional source of liquidity through our $30,000 bank revolving credit facility. Our liquidity needs may change if overall economic conditions worsen and/or +liquidity and credit within the financial markets tightens for an extended period of time, and such conditions impact the collectibility of our customer accounts receivable, impact credit terms with our vendors, or disrupt the supply of raw +materials and services. +Fluctuations in overall stock market valuations may raise questions as to the potential impairment of goodwill and other +long-lived assets. Our annual goodwill impairment review takes place as of June 30 th each year, and is performed at the reporting unit level. While these annual reviews to-date have not resulted in the recording of any impairments, a $6,628 impairment charge has been recorded on the goodwill resulting from the Magellan acquisition due to certain FDA activities related to +Magellan’s lead testing system utilizing venous blood samples (see full description previously within this MD&A). As of September 30, 2017, our stock price was $14.30 per share, compared to our book value per share of $4.02. This +relationship, stock price trading at a 3.6x multiple of book value, is an indicator that the fluctuation in overall stock market valuations and its impact on our stock price has not been a triggering event for further impairment of our goodwill and +other long-lived assets. +As of September 30, 2017, our cash and equivalents balance is $9,846 higher than at the end of fiscal 2016. This increase +results in large part from the combined net effects of (i) operating activities providing $4,132 more net cash, as discussed below; (ii) lowering the quarterly cash dividend rate resulting in $9,383 less in shareholder dividends being +paid, as discussed below; and (iii) principal payments during the year being $2,250 higher during this first full fiscal year of the term loan obligation. +- 42 - +Table of Contents +Net cash provided by operating activities totaled $41,355 during fiscal 2017, an 11% increase from the $37,223 +provided during fiscal 2016. While reflecting the effects of the timing of payments from customers, and to suppliers and taxing authorities, this increase also results in large part from the net effects of (i) decreased inventory levels during +fiscal 2017, compared to increased levels during fiscal 2016; and (ii) decreased accrued employee compensation costs during fiscal 2017, reflecting the payment of $407 of discretionary bonuses to +non-executives related to fiscal 2016 and the timing of regularly scheduled payroll payments. Net cash flows from operating activities and cash on hand are anticipated to be adequate to fund working capital +requirements, capital expenditures and dividends during the next 12 months. +Following the release of results for the fiscal 2017 first quarter, the board +of directors reduced the fiscal 2017 indicated annual cash dividend rate to $0.50 per share (down from $0.80 per share) in order to align it with the stated policy guidelines of the payout ratio to range between 75% and 85% of each fiscal +year’s net earnings. This indicated annual rate represents 75% of fiscal 2017’s non-GAAP diluted earnings per share. +Capital Resources +In connection with the +acquisition of Magellan, the Company entered into a $60,000 five-year term loan and related interest rate swap agreement with a commercial bank, the details of which are set forth in Note 4 of the accompanying Consolidated Financial Statements. In +addition, we have a $30,000 revolving credit facility with a commercial bank that expires March 31, 2021. As of November 29, 2017, there were no borrowings outstanding on this facility and we had 100% borrowing capacity available to us. We +have had no borrowings outstanding under this revolving credit facility during fiscal 2017, 2016 or 2015. +Our capital expenditures totaled $4,467 for +fiscal 2017 and largely related to laboratory equipment, manufacturing equipment and a new business intelligence system. During fiscal 2018 our capital expenditures are estimated to range between approximately $4,000 to $5,000, with the actual +amount dependent upon actual operating results and the phasing of certain projects. Such expenditures may be funded with cash and equivalents on hand, operating cash flows and/or availability under the $30,000 revolving credit facility discussed +above. +- 43 - +Table of Contents +Known Contractual Obligations: +Known contractual obligations and their related due dates were as follows as of September 30, 2017: +Total +Less than 1 +Year +1-3 Years +4-5 Years +More than +5 Years +Operating leases (1) +$ +5,593 +$ +1,978 +$ +2,424 +$ +766 +$ +425 +Purchase obligations (2) +21,764 +18,885 +2,879 +— +— +Loan principal payments (3) +54,750 +4,500 +50,250 +— +— +Scheduled interest payments (3) +4,581 +1,487 +3,094 +— +— +Uncertain income tax positions liability and interest +(4) +682 +682 +— +— +— +Total +$ +87,370 +$ +27,532 +$ +58,647 +$ +766 +$ +425 +(1) +Meridian and its subsidiaries are lessees of (i) office and warehouse buildings in Ohio, Massachusetts, Florida, Australia, Belgium, France, Germany, Singapore, China and the U.K.; (ii) automobiles for use by the +diagnostic direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile and copier machines across all business units, under operating lease agreements that expire at various dates. +(2) +Purchase obligations relate primarily to outstanding purchase orders for inventory, including instruments, service items, and research and development activities. These contractual commitments are not in excess of +expected production requirements over the next twelve months. +(3) +These principal and interest payments relate to the $60,000 five-year term loan with a commercial bank entered into in connection with the acquisition of Magellan, and reflect the impact of an interest rate swap +agreement with the commercial bank, which effectively converts the variable interest rate on the term loan to a fixed rate of 2.76%. The details of the loan and the interest rate swap are set forth in Note 4 of the accompanying Consolidated +Financial Statements. +(4) +As of September 30, 2017, our liabilities for uncertain tax positions and related interest and penalties were $517 and $165, respectively. Due to inherent uncertainties in the timing of settlement of tax positions, +we are unable to estimate the timing of the effective settlement of these obligations. +Other Commitments and Off-Balance Sheet Arrangements : +License Agreements +Meridian has entered into various license agreements that require payment of royalties based on a specified percentage of sales of related products. +Approximately 90% of our royalty expenses relate to our Diagnostics operating segment, where the royalty rates range from 4% to 8%. Meridian expects that payments under these agreements will amount to approximately $2,500 in fiscal 2018. +Off-Balance Sheet Arrangements +We do not utilize special-purpose financing vehicles or have undisclosed off-balance sheet arrangements. +- 44 - +Table of Contents +Market Risk Exposure : +Foreign Currency Risk +We have market risk exposure +related to foreign currency transactions from our operations outside the United States, as well as certain suppliers to our domestic businesses located outside the United States. The foreign currencies where we have market risk exposure are the +Australian dollar, British pound, Chinese yuan, Euro and Singapore dollar. Assessing foreign currency exposures is a component of our overall ongoing risk management process, with such currency risks managed as we deem appropriate. +Concentration of Customers/Products Risk +Our +Diagnostics segment’s revenues from sales through two U.S. distributors were 29% of the segment’s total revenues or 21% of consolidated revenues for fiscal 2017. Additionally, five of our product families accounted for 81% of our +Diagnostics segment’s third-party revenues during fiscal 2017, and 58% of our fiscal 2017 consolidated revenues. +Our Life Science segment’s +revenues from sales of purified antigens and reagents to two diagnostics manufacturing customers were 17% of the segment’s total revenues for fiscal 2017, and 5% of our fiscal 2017 consolidated revenues. +Critical Accounting Policies : +The consolidated +financial statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally accepted in the United States. Such accounting principles require +management to make judgments about estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Listed below are the accounting policies management believes to be critical to +understanding the accompanying Consolidated Financial Statements, along with reference to location of the policy discussion within the accompanying financial statements. The listed policies are considered critical due to the fact that application of +such polices requires the use of significant estimates and assumptions, and the carrying values of related assets and liabilities are material. +Accounting Policy +Location +Within Consolidated +Financial Statements +Examples of Key Estimate Assumptions +Inventories +Note 1(f) +Slow-moving, excess & obsolete inventories +Intangible Assets +Note 1(h) +Triggering events and impairment conditions +Revenue Recognition +Note 1(i) +Distributor price adjustments and fee accruals +Income Taxes +Note 1(k) and Note 5 +Uncertain tax positions and state apportionment factors +- 45 - +Table of Contents +Recent Accounting Pronouncements : +In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which supersedes and +replaces nearly all currently-existing U.S. GAAP revenue recognition guidance including related disclosure requirements. This guidance, including any clarification guidance thereon, will be effective for the Company beginning October 1, 2018 +(fiscal 2019). The Company has prepared an inventory of its existing revenue streams and a preliminary analysis of the revenue recognition criteria applying ASU 2014-09. This analysis is preliminary and our +overall assessment is not yet complete. However, based on the analysis completed to date, aside from certain expanded disclosure requirements, the Company does not currently anticipate that its planned adoption of ASU +2014-09 on a modified retrospective basis will have a material impact on its financial statements. +In February +2016, the FASB issued ASU 2016-02, Leases , which amends the accounting guidance related to leases. These changes, which are designed to increase transparency and comparability among organizations for +both lessees and lessors, include, among other things, requiring recognition of lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Adoption and implementation of the guidance is not required +by the Company until the beginning of fiscal 2020, although early adoption is permitted. The Company expects to begin its assessment of the impact that adoption of this guidance will have on its financial statements in fiscal 2018. +In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting , which +amends the accounting for share-based payment transactions. These changes, which are designed for simplification, involve several aspects of the accounting for share-based transactions, including the income tax consequences, classification of awards +as either equity or liabilities, and classification on the statement of cash flows. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2018, although early adoption is permitted. The Company has +assessed the impact that adoption of this guidance will have, and believes that the impact will primarily relate to the treatment of the differences between stock compensation expense recorded in the Company’s financial statements and the stock +compensation ultimately deducted on its tax returns. The tax effect of such differences is currently recorded in additional paid-in capital and reflected within the financing activities section of the +statement of cash flows. Upon adoption of this guidance, these tax effects will be required to be recorded directly to income tax expense and reflected within the operating activities section of the statement of cash flows. While the impact of +this guidance, which the Company plans to adopt on a prospective basis at the beginning of fiscal 2018, is dependent on numerous factors (e.g., the market price of the Company’s common stock on the equity award grant date, the exercise/lapse +dates of equity awards, and the market price of the Company’s common stock on such exercise/lapse dates), based on the lapsing of a significant equity grant in November 2017, adoption is expected to increase the Company’s fiscal 2018 +effective tax rate by approximately one percentage point. +- 46 - +Table of Contents +In August 2016, the FASB issued ASU 2016-15, Classification of Certain +Cash Receipts and Cash Payments . The update addresses certain specific cash flows and their treatment, with the objective being to reduce the existing diversity in how the items are presented and classified within the statement of cash flows. +Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2019, although early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on the Company’s +statement of cash flows. +In October 2016, the FASB issued ASU 2016-16, Intra-Entity Transfers of Assets Other +Than Inventory , which intends to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Adoption and implementation of the guidance is not required by the Company until the beginning of +fiscal 2019, although early adoption is permitted. While the Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial statements, in light of the levels of such transfer activity within the +Company, adoption of this guidance is not expected to have a significant impact on the Company’s consolidated results of operations, cash flows or financial position. +In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment , which +serves to simplify the process of testing for goodwill impairment by eliminating the “Step 2” comparison of a reporting unit’s implied fair value to its carrying amount. The guidance requires an entity to compare a reporting +unit’s fair value to its carrying amount, and if the carrying amount exceeds the fair value, an impairment equal to the excess carrying amount is recorded; no Step 2 implied fair value comparison is required. The Company early adopted this +guidance during the third quarter of fiscal 2017, as permitted. See Note 1(h) for discussion of Magellan’s goodwill impairment. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +See Market Risk Exposure and Capital Resources under Item 7 above beginning on page 29. +- 47 - +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements +Reports of Independent Registered Public Accounting Firm +49 +Consolidated Statements of Operations for the years ended September +30, 2017, 2016 and 2015 +52 +Consolidated Statements of Comprehensive Income for the years ended September 30, +2017, 2016 and 2015 +53 +Consolidated Balance Sheets as of September 30, 2017 and +2016 +54 +Consolidated Statements of Shareholders’ Equity for the years ended September 30, +2017, 2016 and 2015 +56 +Consolidated Statements of Cash Flows for the years ended September +30, 2017, 2016 and 2015 +57 +Notes to Consolidated Financial Statements +58 +Schedule No. II – Valuation and Qualifying Accounts for the years ended September 30, +2017, 2016 and 2015 +90 +All other supplemental schedules are omitted due to the absence of conditions under which they are required or because the +information is shown in the Consolidated Financial Statements or Notes thereto. +- 48 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +We have audited the accompanying consolidated balance sheets of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the +“Company”) as of September 30, 2017 and 2016, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2017. Our +audits of the basic consolidated financial statements included the financial statement schedule listed in the index appearing under Schedule No. II. These financial statements and financial statement schedule are the responsibility of the +Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we +plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial +statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for +our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of +Meridian Bioscience, Inc. and subsidiaries as of September 30, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2017 in conformity with accounting principles +generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material +respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board +(United States), the Company’s internal control over financial reporting as of September 30, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations +of the Treadway Commission (COSO), and our report dated November 29, 2017 expressed an adverse opinion. +/s/ GRANT THORNTON LLP +Cincinnati, Ohio +November 29, 2017 +- 49 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +We have audited the internal control over financial reporting of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the +“Company”) as of September 30, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s +management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal +Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan +and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial +reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the +circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made +only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could +have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or +detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or +procedures may deteriorate. +A material weakness is a deficiency, or combination of control deficiencies, in internal control over financial reporting, +such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and +included in management’s assessment. +Information Technology General Controls (“ITGC”) intended to restrict access to +certain data and applications were not adequate, resulting in inappropriate access at both the Information Technology and end user levels within an application impacting financial reporting function and controls. +- 50 - +Table of Contents +In our opinion, because of the effect of the material weakness described above on the achievement of the +objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of September 30, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by +COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial +statements of the Company as of and for the year ended September 30, 2017. The material weakness identified above was considered in determining the nature, timing, and extent of audit tests applied in our audit of the September 30, 2017 consolidated +financial statements, and this report does not affect our report dated November 29, 2017, which expressed an unqualified opinion on those financial statements. +/s/ GRANT THORNTON LLP +Cincinnati, Ohio +November 29, 2017 +- 51 - +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2017 +2016 +2015 +Net Revenues +$ +200,771 +$ +196,082 +$ +194,830 +Cost of Sales +75,938 +68,295 +72,948 +Gross Profit +124,833 +127,787 +121,882 +Operating Expenses: +Research and development +15,680 +13,815 +12,605 +Selling and marketing +32,101 +29,871 +25,601 +General and administrative +32,280 +30,565 +27,616 +CEO transition and IP defense costs +762 +— +— +Goodwill impairment charge +6,628 +— +— +Sales and marketing leadership reorganization costs +— +677 +— +Acquisition-related costs +— +1,481 +— +Total operating expenses +87,451 +76,409 +65,822 +Operating Income +37,382 +51,378 +56,060 +Other Income (Expense): +Interest income +171 +67 +23 +Interest expense +(1,642 +) +(897 +) +— +Other, net +518 +96 +(1,020 +) +Total other expense +(953 +) +(734 +) +(997 +) +Earnings Before Income Taxes +36,429 +50,644 +55,063 +Income Tax Provision +14,872 +18,415 +19,523 +Net Earnings +$ +21,557 +$ +32,229 +$ +35,540 +Earnings Per Share Data: +Basic earnings per common share +$ +0.51 +$ +0.77 +$ +0.85 +Diluted earnings per common share +$ +0.51 +$ +0.76 +$ +0.85 +Common shares used for basic earnings per common share +42,188 +42,010 +41,659 +Effect of dilutive stock options and restricted share units +383 +383 +353 +Common shares used for diluted earnings per common share +42,571 +42,393 +42,012 +Dividends declared per common share +$ +0.575 +$ +0.80 +$ +0.80 +Anti-dilutive Securities: +Common share options and restricted share units +873 +462 +551 +The accompanying notes are an integral part of these consolidated financial statements. +- 52 - +Table of Contents +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2017 +2016 +2015 +Net Earnings +$ +21,557 +$ +32,229 +$ +35,540 +Other comprehensive income (loss): +Foreign currency translation adjustment +1,616 +(2,732 +) +(2,639 +) +Unrealized gain (loss) on cash flow hedge +1,544 +(729 +) +— +Income taxes related to items of other comprehensive income +(590 +) +275 +— +Other comprehensive income (loss), net of tax +2,570 +(3,186 +) +(2,639 +) +Comprehensive Income +$ +24,127 +$ +29,043 +$ +32,901 +The accompanying notes are an integral part of these consolidated financial statements. +- 53 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2017 +2016 +Assets +Current Assets: +Cash and equivalents +$ +57,072 +$ +47,226 +Accounts receivable, less allowances of $307 and $334, respectively +29,106 +27,102 +Inventories +41,493 +45,057 +Prepaid expenses and other current assets +6,204 +7,406 +Total current assets +133,875 +126,791 +Property, Plant and Equipment, at Cost: +Land +1,162 +1,155 +Buildings and improvements +32,207 +31,487 +Machinery, equipment and furniture +48,836 +45,085 +Construction in progress +1,895 +1,947 +Subtotal +84,100 +79,674 +Less: accumulated depreciation and amortization +53,590 +49,224 +Net property, plant and equipment +30,510 +30,450 +Other Assets: +Goodwill +54,926 +61,982 +Other intangible assets, net +26,704 +29,855 +Restricted cash +1,000 +1,000 +Deferred instrument costs, net +1,368 +1,392 +Fair value of interest rate swap +815 +— +Deferred income taxes +158 +205 +Other assets +421 +353 +Total other assets +85,392 +94,787 +Total assets +$ +249,777 +$ +252,028 +The accompanying notes are an integral part of these consolidated financial statements. +- 54 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2017 +2016 +Liabilities and Shareholders’ Equity +Current Liabilities: +Accounts payable +$ +7,719 +$ +7,627 +Accrued employee compensation costs +4,536 +7,106 +Current portion of acquisition consideration +2,095 +— +Other accrued expenses +2,789 +2,606 +Current portion of long-term debt +4,500 +3,750 +Income taxes payable +1,248 +1,482 +Total current liabilities +22,887 +22,571 +Non-Current +Liabilities +Acquisition consideration +235 +2,383 +Post-employment benefits +2,468 +2,305 +Fair value of interest rate swap +— +729 +Long-term debt +50,147 +54,610 +Deferred income taxes +4,455 +2,958 +Total non-current liabilities +57,305 +62,985 +Commitments and Contingencies +Shareholders’ Equity: +Preferred stock, no par value; 1,000,000 shares authorized; none issued +— +— +Common shares, no par value; 71,000,000 shares authorized, 42,207,317 and 42,106,587 issued, +respectively +— +— +Additional paid-in capital +125,608 +122,356 +Retained earnings +46,923 +49,632 +Accumulated other comprehensive loss +(2,946 +) +(5,516 +) +Total shareholders’ equity +169,585 +166,472 +Total liabilities and shareholders’ equity +$ +249,777 +$ +252,028 +The accompanying notes are an integral part of these consolidated financial statements. +- 55 - +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (dollars and shares in +thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +Common +Shares +Issued +Additional +Paid-in +Capital +Retained +Earnings +Accum Other +Comp +Income +(Loss) +Total +Balance at September 30, 2014 +41,622 +$ +111,851 +$ +48,869 +$ +309 +$ +161,029 +Cash dividends paid - $0.80 per share +— +— +(33,357 +) +— +(33,357 +) +Exercise of stock options +187 +1,976 +— +— +1,976 +Conversion of restricted share units +29 +— +— +— +— +Stock compensation expense +— +3,324 +— +— +3,324 +Net earnings +— +— +35,540 +— +35,540 +Foreign currency translation adjustment +— +— +— +(2,639 +) +(2,639 +) +Balance at September 30, 2015 +41,838 +117,151 +51,052 +(2,330 +) +165,873 +Cash dividends paid - $0.80 per share +— +— +(33,649 +) +— +(33,649 +) +Exercise of stock options +152 +2,294 +— +— +2,294 +Conversion of restricted share units +117 +— +— +— +— +Stock compensation expense +— +2,911 +— +— +2,911 +Net earnings +— +— +32,229 +— +32,229 +Foreign currency translation adjustment +— +— +— +(2,732 +) +(2,732 +) +Hedging activity, net of tax +— +— +— +(454 +) +(454 +) +Balance at September 30, 2016 +42,107 +122,356 +49,632 +(5,516 +) +166,472 +Cash dividends paid - $0.575 per share +— +— +(24,266 +) +— +(24,266 +) +Exercise of stock options +18 +(129 +) +— +— +(129 +) +Conversion of restricted share units +82 +— +— +— +— +Stock compensation expense +— +3,381 +— +— +3,381 +Net earnings +— +— +21,557 +— +21,557 +Foreign currency translation adjustment +1,616 +1,616 +Hedging activity, net of tax +— +— +— +954 +954 +Balance at September 30, 2017 +42,207 +$ +125,608 +$ +46,923 +$ +(2,946 +) +$ +169,585 +The accompanying notes are an integral part of these consolidated financial statements. +- 56 - +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2017 +2016 +2015 +Cash Flows From Operating Activities +Net earnings +$ +21,557 +$ +32,229 +$ +35,540 +Non-cash items included in net earnings: +Depreciation of property, plant and equipment +4,342 +3,937 +3,470 +Amortization of intangible assets +3,776 +2,690 +1,748 +Amortization of deferred instrument costs +972 +1,091 +1,391 +Stock-based compensation +3,381 +2,911 +3,324 +Goodwill impairment charge +6,628 +— +— +Deferred income taxes +1,474 +(233 +) +(122 +) +Losses on long-lived assets +— +659 +94 +Change in current assets, net of acquisition +3,481 +(8,115 +) +(6,079 +) +Change in current liabilities, net of acquisition +(3,535 +) +2,237 +3,238 +Other, net +(721 +) +(183 +) +205 +Net cash provided by operating activities +41,355 +37,223 +42,809 +Cash Flows From Investing Activities +Purchase of property, plant and equipment +(4,467 +) +(4,004 +) +(4,613 +) +Purchase of equity method investment +— +(600 +) +— +Proceeds from sale of assets +— +— +1,138 +Purchase of intangibles and other assets +— +— +(151 +) +Acquisition of Magellan, net of cash acquired +— +(62,091 +) +— +Net cash used for investing activities +(4,467 +) +(66,695 +) +(3,626 +) +Cash Flows From Financing Activities +Dividends paid +(24,266 +) +(33,649 +) +(33,357 +) +Proceeds from term loan, net of issuance costs +— +59,860 +— +Payments on term loan +(3,750 +) +(1,500 +) +— +Proceeds and tax benefits from exercises of stock options +303 +2,494 +2,614 +Net cash provided by (used for) financing activities +(27,713 +) +27,205 +(30,743 +) +Effect of Exchange Rate Changes on Cash and Equivalents +671 +(480 +) +(1,514 +) +Net Increase (Decrease) in Cash and Equivalents +9,846 +(2,747 +) +6,926 +Cash and Equivalents at Beginning of Period +47,226 +49,973 +43,047 +Cash and Equivalents at End of Period +$ +57,072 +$ +47,226 +$ +49,973 +Supplemental Cash Flow Information +Cash paid for interest +$ +1,605 +$ +879 +$ +— +Cash paid for income taxes +$ +12,613 +$ +17,915 +$ +20,168 +The accompanying notes are an integral part of these consolidated financial statements. +- 57 - +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +Meridian Bioscience, Inc. and Subsidiaries +(dollars +and shares in thousands, except per share data) +(1) +Summary of Significant Accounting Policies +(a) +Nature of Business - Meridian is a fully-integrated life science company whose principal businesses are (i) the development, manufacture and distribution of clinical diagnostic test kits primarily for +certain gastrointestinal, viral, respiratory and parasitic infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and +bioresearch reagents used by researchers and other diagnostic manufacturers. +(b) +Principles of Consolidation - The consolidated financial statements include the accounts of Meridian Bioscience, Inc. and its subsidiaries. All intercompany accounts and transactions have been eliminated in +consolidation. Unless the context requires otherwise, references to “Meridian,” “we,” “us,” “our” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +(c) +Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts +of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. +(d) +Foreign Currency Translation - Assets and liabilities of foreign operations are translated using year-end exchange rates with gains or losses resulting from translation +included as a separate component of accumulated other comprehensive income or loss. Revenues and expenses are translated using exchange rates prevailing during the year. We also recognize foreign currency transaction gains and losses on certain +assets and liabilities that are denominated in the Australian dollar, British pound, Chinese yuan, Euro and Singapore dollar currencies. These gains and losses are included in other income and expense in the accompanying Consolidated Statements of +Operations. +(e) +Cash, Cash Equivalents and Investments - The primary objectives of our investment activities are to preserve capital and provide sufficient liquidity to meet operating requirements and fund strategic +initiatives such as acquisitions. We maintain a written investment policy that governs the management of our investments in fixed income securities. This policy, among other things, provides that we may purchase only high credit-quality securities +that have short-term ratings of at least A-2, P-2 and F-2, and long-term ratings of at least A, Baa1 and A, by +Standard & Poor’s, Moody’s and Fitch, respectively, at the time of purchase. We consider short-term investments with original maturities of 90 days or less to be cash equivalents, including overnight repurchase agreements and +institutional money market funds. At times our investments of cash and equivalents with various high credit quality financial institutions may be in excess of the Federal Deposit Insurance Corporation (FDIC) insurance limit. +- 58 - +Table of Contents +Our investment portfolio includes the following components: +September 30, 2017 +September 30, 2016 +Cash and +Equivalents +Other +Cash and +Equivalents +Other +Overnight repurchase agreements +$ +— +$ +— +$ +9,988 +$ +— +Institutional money market funds +20,104 +— +10,020 +— +Cash on hand – +Restricted +— +1,000 +— +1,000 +Unrestricted +36,968 +— +27,218 +— +Total +$ +57,072 +$ +1,000 +$ +47,226 +$ +1,000 +(f) +Inventories - Inventories are stated at the lower of cost or market. Cost is determined on a first-in, first-out (FIFO) basis. +illumi gene instruments are carried in inventory until customer placement, at which time they are transferred to deferred illumi gene instrument costs, unless sold outright. Similarly, Magellan’s blood +lead testing instruments are carried in inventory until they are sold outright or placed with a customer under Magellan’s customer reagent rental program, at which time they are transferred to property, plant and equipment. +We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and +other identified exposures. Such reserves were $2,059 and $2,680 at September 30, 2017 and 2016, respectively. We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and market conditions +were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. Such adjustments would negatively affect gross profit margin and overall results of operations. +(g) +Property, Plant and Equipment - Property, plant and equipment are stated at cost. Upon retirement or other disposition, the cost and related accumulated depreciation are removed from the accounts and the +resulting gain or loss is reflected in earnings. Maintenance and repairs are expensed as incurred. Depreciation is computed on the straight-line method in amounts sufficient to write-off the cost over the +estimated useful lives, generally as follows: +Buildings and improvements - 18 to 40 years +Leasehold improvements - life of the lease +Machinery, equipment and furniture - 3 to 10 years +Computer equipment and software - 3 to 5 years +Instruments under customer reagent rental arrangements - 5 years +- 59 - +Table of Contents +(h) +Intangible Assets - Goodwill is subject to an annual impairment review (or more frequently if impairment indicators arise) at the reporting unit level, which we perform annually as of June 30, the end of our +third fiscal quarter. A reporting unit is generally an operating segment or one level below an operating segment that constitutes a business for which discrete financial information is available and regularly reviewed by segment management. At +September 30, 2017, we had six reporting units, four of which contained goodwill (Americas Diagnostics, Bioline (molecular components), Life Science-U.S. (immunoassay components) and Magellan). We review +our reporting unit structure each year as part of our annual goodwill impairment test, or more frequently in the event of changes in our structure. Goodwill is considered impaired if the carrying value of the reporting unit exceeds its fair value. +We have no intangible assets with indefinite lives other than goodwill. +During fiscal 2017, we performed quantitative +assessments as of June 30, 2017 for each of our Americas Diagnostics, Bioline and Life Science-U.S. reporting units, noting the separate Magellan discussion below. As part of this assessment, fair value, +as determined through a valuation performed by a third party, was calculated via both market (comparable company) and income (discounted cash flows) approaches. Based upon these approaches, the fair values of each reporting unit exceeded their +carrying values; therefore, each of the Americas Diagnostics, Bioline and Life Science-U.S. reporting units satisfied the quantitative assessment for fiscal 2017. +During the quarter ended June 30, 2017, the events described below occurred, indicating that impairment of the goodwill recorded as part +of the Magellan acquisition had occurred. +On May 17, 2017, the FDA issued a field safety notice advising customers to discontinue use of +Magellan’s lead testing systems with venous blood samples. This field safety notice was followed by product recall notices on May 25 th and June +5 th . Magellan’s lead testing systems are capable of processing both capillary and venous blood samples. Magellan’s LeadCare Plus and LeadCare Ultra systems, which account for +approximately 10% of Magellan’s annual revenues, are used predominantly with venous blood samples. Magellan’s LeadCare and LeadCare II systems are predominantly used with capillary blood samples. +Subsequent to the issuances of these field safety and product recall notices, the FDA completed an inspection of Magellan’s quality +system, and issued its Form 483, Inspectional Observations, on June 29, 2017, which was expectedly followed by a Warning Letter issued on October 23, 2017. The Warning Letter requires periodic reporting on our remediation progress. +As a result of these matters, we expect to experience delays in reinstating venous blood sample testing on our LeadCare products, as well as in +obtaining 510(k) clearance for new Magellan products. We also expect delays in obtaining export certifications for Magellan products during the remediation period. In light of these factors and their impacts, during our third fiscal quarter, it was +determined that a potential +- 60 - +Table of Contents +impairment of goodwill recorded in connection with the acquisition of Magellan had occurred (i.e., a “triggering event”). With the assistance of an independent valuation firm, +Magellan’s fair value was calculated via both market (comparable company) and income (discounted cash flows) approaches. Based upon these approaches, it was determined that the carrying value of the Magellan reporting unit did, in fact, exceed +its fair value. As a result, an impairment charge of $6,628, on both a pre-tax and after-tax basis, was recorded during the third quarter and is reflected as a separate operating expense line item within the accompanying Consolidated Statement of +Operations for the year ended September 30, 2017. This quantitative assessment as of May 31, 2017 was supplemented by a qualitative assessment of Magellan’s goodwill as of June 30, 2017, with such assessment indicating that no additional +impairment existed. +No impairments were indicated or recorded from the analyses performed for fiscal 2016 or 2015. +During fiscal 2017, goodwill decreased $7,056, reflecting (i) a $767 acquisition measurement period adjustment downward related to +Magellan (Diagnostics operating segment; see Note 2); (ii) the $6,628 impairment charge related to Magellan; and (iii) a $339 increase from the currency translation adjustment on the goodwill of the Life Science segment’s Bioline Group. +The increase of $39,633 in fiscal 2016 reflects the addition of $41,358 from the acquisition of Magellan and a $1,725 decrease from the currency translation adjustments related to the Bioline Group. +A summary of Meridian’s acquired intangible assets subject to amortization, as of September 30, 2017 and 2016 is as follows: +2017 +2016 +As of September 30, +Gross +Carrying +Value +Accum. +Amort. +Gross +Carrying +Value +Accum. +Amort. +Manufacturing technologies, core products and cell lines +$ +22,332 +$ +12,807 +$ +21,921 +$ +11,540 +Trade names, licenses and patents +8,689 +4,398 +9,037 +3,947 +Customer lists, customer relationships and supply agreements +24,562 +11,854 +24,385 +10,511 +Non-compete agreements +720 +540 +680 +170 +$ +56,303 +$ +29,599 +$ +56,023 +$ +26,168 +The actual aggregate amortization expense for these intangible assets for fiscal 2017, 2016 and 2015 was +$3,776, $2,690 and $1,748, respectively. The estimated aggregate amortization expense for these intangible assets for each of the five succeeding fiscal years is as follows: fiscal 2018 - $3,561, fiscal 2019 - $3,340, fiscal 2020 - $3,176, fiscal +2021 - $2,561 and fiscal 2022 - $2,182. +Long-lived assets, excluding goodwill, are reviewed for impairment when events or circumstances +indicate that such assets may not be recoverable at their carrying value. Whether an event or circumstance triggers an impairment is determined by comparing an estimate of the asset’s future undiscounted cash flows to its carrying value. If +impairment has occurred, it is measured by a fair-value based calculation. +- 61 - +Table of Contents +Our ability to recover the carrying value of our intangible assets, both identifiable intangibles +and goodwill, is dependent upon the future cash flows of the related acquired businesses and assets. We make judgments and assumptions regarding future cash flows, including sales levels, gross profit margins, operating expense levels, working +capital levels, and capital expenditures. With respect to identifiable intangibles and fixed assets, we also make judgments and assumptions regarding useful lives. +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant under-performance +relative to historical or projected operating results; (ii) negative industry trends; (iii) sales levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; and +(v) other factors. +If actual cash flows are less favorable than projections, this could trigger impairment of intangible assets and +other long-lived assets. If impairment were to occur, this would negatively affect overall results of operations. Aside from the Magellan matter noted above, no triggering events have been identified by the Company for fiscal 2017, 2016 or 2015. +(i) +Revenue Recognition and Accounts Receivable - Revenue is generally recognized from sales when product is shipped and title has passed to the customer. Revenue is reduced in the period of sale for fees paid to +distributors, which are inseparable from the distributor’s purchase of our product and for which we receive no goods or services in return. Such fees totaled $787 in fiscal 2017. +Revenue for the Diagnostics segment is reduced at the date of sale for product price adjustments due to certain distributors under local +contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the +period that they become known. Such accruals were $4,190 at September 30, 2017 and $4,178 at September 30, 2016, and have been netted against accounts receivable. +Revenue for our Diagnostics segment includes revenue for our illumi gene +molecular test system. This system includes an instrument, instrument accessories and test kits. In markets where the test system is sold via multiple deliverable arrangements, the cost of the instrument and instrument +accessories is deferred upon placement at a customer and amortized on a straight-line basis into cost of sales over the expected utilization period, generally three years. +- 62 - +Table of Contents +We evaluate whether each deliverable in the arrangement is a separate unit of accounting. The +significant deliverables are an instrument, instrument accessories (e.g., printer) and test kits. An instrument and instrument accessories are delivered to the customer prior to the start of the customer utilization period in order to accommodate +customer set-up and installation. There is de minimis consideration received from the customer at the time of instrument placement. We have determined that the instrument and instrument accessories are +not a separate unit of accounting because such equipment can only be used to process and read the results from our illumi gene diagnostic tests (i.e., our instrument and test kits function together to deliver a diagnostic test +result), and therefore the instrument and instrument accessories do not have standalone value to the customer. Consequently, there is no revenue allocated to the placement of the instrument and instrument accessories. Test kits are delivered to the +customer over the utilization period of the instrument, which we estimate has a useful life of three years. Our average customer contract period, including estimated renewals, is at least equal to the estimated three-year utilization period. Revenue +for the sale of test kits is recognized upon shipment and transfer of title to the customers. +In markets where the test system is not sold +via multiple deliverable arrangements, the cost of the instrument and instrument accessories is charged to cost of sales at the time of shipment and transfer of title to the customer. Revenue for the sales of instruments, instrument accessories and +test kits is recognized upon shipment and transfer of title to the customers. In these markets, our illumi gene molecular test system is sold to independent distributors who inventory the instruments, instrument accessories and +test kits for resale to end-users. +Our products are generally not subject to a customer right of +return except for product recall events under the rules and regulations of the Food and Drug Administration or equivalent agencies outside the United States. In this circumstance, the costs to replace affected products would be accrued at the time a +loss was probable and estimable. +Trade accounts receivable are recorded in the accompanying Consolidated Balance Sheets at invoiced +amounts less provisions for distributor price adjustments under local contracts and doubtful accounts. The allowance for doubtful accounts represents our estimate of probable credit losses and is based on historical +write-off experience and known conditions that would likely lead to non-payment. The allowance for doubtful accounts and related metrics, such as days’ sales +outstanding, are reviewed monthly. Accounts with past due balances over 90 days are reviewed individually for collectibility. Customer invoices are charged off against the allowance when we believe it is probable that the invoices will not be paid. +(j) +Research and Development Costs - Research and development costs are charged to expense as incurred. Research and development costs include, among other things, salaries and wages for research scientists, +materials and supplies used in the development of new products, costs for development of instrumentation equipment, costs for clinical trials, and costs for facilities and equipment. +- 63 - +Table of Contents +(k) +Income Taxes - The provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial +reporting and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, +typically occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +We account for uncertain tax positions using a benefit recognition model with a two-step approach: +(i) a more-likely-than-not recognition criterion; and (ii) a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately +realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit is recorded. We recognize accrued interest related to unrecognized tax benefits as a portion of our income +tax provision in the Consolidated Statements of Operations. See Note 5. +(l) +Stock-Based Compensation - We recognize compensation expense for all share-based awards made to employees, based upon the fair value of the share-based award on the date of the grant. See Note 6(b). +(m) +Comprehensive Income (Loss) - Comprehensive income (loss) represents the net change in shareholders’ equity during a period from sources other than transactions with shareholders. As reflected in the +accompanying Consolidated Statements of Comprehensive Income, our comprehensive income is comprised of net earnings, foreign currency translation, unrealized losses on our cash flow hedge, and the income taxes thereon. +(n) +Shipping and Handling Costs - Shipping and handling costs invoiced to customers are included in net revenues. Costs to distribute products to customers, including freight costs, warehousing costs, and other +shipping and handling activities are included in cost of sales. +(o) +Non-Income Government-Assessed Taxes - We classify all non-income, government-assessed taxes (sales, use and value-added) collected +from customers and remitted by us to appropriate revenue authorities, on a net basis (excluded from net revenues) in the accompanying Consolidated Statements of Operations. +(p) +Recent Accounting Pronouncements – In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which supersedes and replaces +nearly all currently-existing U.S. GAAP revenue recognition guidance including related disclosure requirements. This guidance, including any clarification guidance thereon, will be effective for the Company beginning October 1, 2018 (fiscal +2019). The Company has prepared an inventory of its existing revenue streams and a preliminary analysis of the revenue recognition criteria applying ASU 2014-09. This analysis is preliminary and our overall +assessment is not yet complete. However, based on the analysis completed to date, aside from certain expanded disclosure requirements, the Company does not currently anticipate that its planned adoption of ASU +2014-09 on a modified retrospective basis will have a material impact on its financial statements. +- 64 - +Table of Contents +In February 2016, the FASB issued ASU 2016-02, +Leases , which amends the accounting guidance related to leases. These changes, which are designed to increase transparency and comparability among organizations for both lessees and lessors, include, among other things, requiring recognition +of lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2020, although early adoption is +permitted. The Company expects to begin its assessment of the impact that adoption of this guidance will have on its financial statements in fiscal 2018. +In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment +Accounting , which amends the accounting for share-based payment transactions. These changes, which are designed for simplification, involve several aspects of the accounting for share-based transactions, including the income tax consequences, +classification of awards as either equity or liabilities, and classification on the statement of cash flows. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2018, although early adoption is +permitted. The Company has assessed the impact that adoption of this guidance will have, and believes that the impact will primarily relate to the treatment of the differences between stock compensation expense recorded in the Company’s +financial statements and the stock compensation ultimately deducted on its tax returns. The tax effect of such differences is currently recorded in additional paid-in capital and reflected within the +financing activities section of the statement of cash flows. Upon adoption of this guidance, these tax effects will be required to be recorded directly to income tax expense and reflected within the operating activities section of the statement of +cash flows. While the impact of this guidance, which the Company plans to adopt on a prospective basis at the beginning of fiscal 2018, is dependent on numerous factors (e.g., the market price of the Company’s common stock on the equity +award grant date, the exercise/lapse dates of equity awards, and the market price of the Company’s common stock on such exercise/lapse dates), based on the lapsing of a significant equity grant in November 2017, adoption is expected to increase +the Company’s fiscal 2018 effective tax rate by approximately one percentage point. +In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments . The update addresses certain specific cash flows and their treatment, with the objective being to reduce the existing diversity in how the +items are presented and classified within the statement of cash flows. Adoption and implementation of the guidance is not required by the Company until the beginning of fiscal 2019, although early adoption is permitted. Adoption of this guidance is +not expected to have a significant impact on the Company’s statement of cash flows. +- 65 - +Table of Contents +In October 2016, the FASB issued ASU 2016-16, +Intra-Entity Transfers of Assets Other Than Inventory , which intends to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Adoption and implementation of the guidance is not +required by the Company until the beginning of fiscal 2019, although early adoption is permitted. While the Company has not yet completed its assessment of the impact that adoption of this guidance will have on its financial statements, in light of +the levels of such transfer activity within the Company, adoption of this guidance is not expected to have a significant impact on the Company’s consolidated results of operations, cash flows or financial position. +In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill +Impairment , which serves to simplify the process of testing for goodwill impairment by eliminating the “Step 2” comparison of a reporting unit’s implied fair value to its carrying amount. The guidance requires an entity to +compare a reporting unit’s fair value to its carrying amount, and if the carrying amount exceeds the fair value, an impairment equal to the excess carrying amount is recorded; no Step 2 implied fair value comparison is required. The Company +early adopted this guidance during the third quarter of fiscal 2017, as permitted. See Note 1(h) for discussion of Magellan’s goodwill impairment. +(q) +Reclassifications - Certain reclassifications have been made to the prior fiscal year financial statements to conform to the current year presentation. Such reclassifications had no impact on net earnings or +shareholders’ equity. +(2) +Magellan Acquisition +On March 24, 2016, we acquired all of the outstanding common stock of +Magellan Biosciences, Inc., and its wholly-owned subsidiary Magellan Diagnostics, Inc. (collectively, “Magellan”), for $67,874, utilizing the proceeds from a new $60,000 five-year term loan and cash and equivalents on hand. An amount of +the acquisition consideration totaling $2,330 remains payable to the sellers, pending the realization of tax benefits for certain net operating loss carryforwards in future tax returns, which is expected to be paid in fiscal 2018 and fiscal 2019 +upon filing of our U.S. tax returns. Headquartered near Boston, Massachusetts, Magellan is a leading manufacturer of FDA-cleared products for the +point-of-care testing of blood to diagnose lead poisoning in children and adults. +As a result of the consideration paid exceeding the preliminary fair value of the net assets acquired, goodwill in the amount of $40,591 was originally +recorded in connection with this acquisition, none of which is deductible for tax purposes. As of June 30, 2017, the goodwill recorded in connection with the acquisition was written down to $33,963 (see Note 1(h) for a discussion of the $6,628 +impairment write-down). This goodwill results largely from the addition of Magellan’s complementary customer base and distribution channels, industry reputation in the U.S. as a leader in lead testing, and management talent and workforce. Our +fiscal 2016 Consolidated Statement of Operations includes $1,105 of acquisition-related costs related to the Magellan acquisition, which are reflected as Operating Expenses. +- 66 - +Table of Contents +The Magellan results of operations, which are included in our fiscal 2017 and fiscal 2016 Consolidated Statements +of Operations and reported as part of the Diagnostics operating segment, include: +(i) +$0 and $181 of cost of sales in fiscal 2017 and fiscal 2016, respectively, related to the roll-out of fair value inventory adjustments for sales of products that were in +Magellan’s inventory on the date of acquisition and, therefore, were valued at fair value, rather than manufactured cost, in the opening balance sheet; and +(ii) +$2,736 and $1,311 of general and administrative expenses in fiscal 2017 and fiscal 2016, respectively, related to the amortization of specific identifiable intangible assets recorded on the opening balance sheet +including customer relationships, technology, non-compete agreements and trade names. +The results +of Magellan included in the Company’s accompanying consolidated results are as follows, reflecting the items noted above, including the $6,628 goodwill impairment charge, and excluding interest expense on the debt secured by Meridian in +connection with the transaction: +2017 +2016 +2,015 +Net Revenues +$ +18,061 +$ +10,034 +$ +— +Net Earnings +$ +(5,916 +) +$ +848 +$ +— +- 67 - +Table of Contents +The recognized amounts of identifiable assets acquired and liabilities assumed in the acquisition of Magellan are +as follows: +March 24, +2016 +(as initially +reported) +Measurement +Period +Adjustments +March 24, +2016 +(as adjusted) +Fair value of assets acquired - +Cash and equivalents +$ +3,400 +$ +— +$ +3,400 +Accounts receivable +1,700 +— +1,700 +Inventories +1,400 +— +1,400 +Other current assets +300 +— +300 +Property, plant and equipment +2,800 +(200 +) +2,600 +Goodwill +42,800 +(2,200 +) +40,600 +Other intangible assets (estimated useful life): +Customer relationships (15 years) +12,600 +300 +12,900 +Technology (10 years) +10,600 +300 +10,900 +Non-compete agreements (2 years) +700 +— +700 +Trade names (approximate 9 year weighted average) +3,700 +(700 +) +3,000 +80,000 +(2,500 +) +77,500 +Fair value of liabilities assumed - +Accounts payable and accrued expenses +1,600 +100 +1,700 +Deferred income tax liabilities +10,600 +(2,700 +) +7,900 +Total consideration paid (including $2,400 accrued to be paid) +$ +67,800 +$ +100 +$ +67,900 +The consolidated pro forma results of the combined entities of Meridian and Magellan, had the acquisition date been +October 1, 2015, are as follows for the periods indicated: +(UNAUDITED) +Fiscal Year Ended September 30, +2017 +2016 +Net Revenues +$ +200,771 +$ +203,720 +Net Earnings +$ +21,557 +$ +32,226 +These pro forma amounts have been calculated by including the results of Magellan, and adjusting the combined results to give +effect to the following, as if the acquisition had been consummated on October 1, 2015, together with the consequential tax effects thereon: +(i) +remove the effect of transaction costs incurred by the Company ($1,105 in fiscal 2016); +(ii) +reflect the additional depreciation and amortization that would have been charged in connection with the fair value adjustments to inventory, property, plant and equipment, and identifiable intangible assets ($1,412 in +fiscal 2016); +- 68 - +Table of Contents +(iii) +reflect the additional stock compensation expense related to equity-based awards granted under the Company’s 2012 Stock Incentive Plan to certain Magellan employees in accordance with executed employee agreements, +and to certain Meridian employees to reward them for their efforts in connection with the transaction ($95 in fiscal 2016); and +(iv) +reflect the additional interest expense that would have been incurred on the Company’s $60,000 term note ($789 in fiscal 2016). +(3) +Inventories +Inventories are comprised of the following: +As of September 30, +2017 +2016 +Raw materials +$ +6,575 +$ +7,639 +Work-in-process +11,559 +13,146 +Finished goods - instruments +1,460 +2,378 +Finished goods - kits and reagents +21,899 +21,894 +Total +$ +41,493 +$ +45,057 +(4) +Bank Credit Arrangements +In connection with the acquisition of Magellan (see Note 2), on +March 22, 2016 the Company entered into a $60,000 five-year term loan with a commercial bank. The term loan requires quarterly principal and interest payments, with interest at a variable rate tied to LIBOR, and a balloon principal payment due +March 31, 2021. The required principal payments on the term loan for each of the remaining fiscal years are as follows: fiscal 2018 - $4,500, fiscal 2019 - $5,250, fiscal 2020 - $6,000, and fiscal 2021 - $39,000. In light of the term +loan’s interest being determined on a variable rate basis, the fair value of the term loan at September 30, 2017 approximates the current carrying value reflected in the accompanying Consolidated Balance Sheet. +In order to limit exposure to volatility in the LIBOR interest rate, the Company and the commercial bank also entered into an interest rate swap that +effectively converts the variable interest rate on the term loan to a fixed rate of 2.76%. With an initial notional balance of $60,000, the interest rate swap was established with critical terms identical to those of the term loan, including +(i) notional reduction amounts and dates; (ii) LIBOR settlement rates; (iii) rate reset dates; and (iv) term/maturity. Due to this, the interest swap has been designated as an effective cash flow hedge, with changes in fair value +reflected as a separate component of other comprehensive income in the accompanying Consolidated Statements of Comprehensive Income. At September 30, 2017 and 2016, the fair value of the interest rate swap was an asset of $815 and a liability +of $729, respectively, and is reflected as a non-current asset and non-current liability, respectively, in the accompanying Consolidated Balance Sheets. This fair value +was determined by reference to a third party valuation, and is considered a Level 2 input within the fair value hierarchy of valuation techniques. +- 69 - +Table of Contents +In addition, the Company maintains a $30,000 revolving credit facility with a commercial bank, which expires +March 31, 2021. There were no borrowings outstanding on this revolving credit facility at September 30, 2017 or September 30, 2016. +The +term loan and revolving credit facility are collateralized by the business assets of the Company’s U.S. subsidiaries and require compliance with financial covenants that limit the amount of debt obligations and require a minimum level of +coverage of fixed charges, as defined in the borrowing agreement. As of September 30, 2017, the Company is in compliance with all covenants. The Company is also required to maintain a cash compensating balance with the bank in the amount of +$1,000, and is in compliance with this requirement. +(5) +Income Taxes +(a) +Earnings before income taxes, and the related provision for income taxes for the years ended September 30, 2017, 2016 and 2015 were as follows: +Year Ended September 30, +2017 +2016 +2015 +Domestic +$ +31,885 +$ +44,795 +$ +50,653 +Foreign +4,544 +5,849 +4,410 +Total earnings before income taxes +$ +36,429 +$ +50,644 +$ +55,063 +Provision (credit) for income taxes - +Federal - +Current +$ +11,262 +$ +16,178 +$ +16,152 +Temporary differences +Fixed asset basis differences and depreciation +(181 +) +(45 +) +50 +Intangible asset basis differences and amortization +(1,158 +) +(744 +) +(421 +) +Currently non-deductible expenses and reserves +884 +(694 +) +217 +Stock-based compensation +(635 +) +129 +126 +Net operating loss carryforwards utilized +1,831 +— +— +Tax credit carryforwards utilized +67 +41 +250 +Other, net +99 +181 +19 +Subtotal +12,169 +15,046 +16,393 +State and local +1,900 +2,421 +2,236 +Foreign +803 +948 +894 +Total income tax provision +$ +14,872 +$ +18,415 +$ +19,523 +- 70 - +Table of Contents +(b) +The following is a reconciliation between the statutory U.S. income tax rate and the effective rate derived by dividing the provision for income taxes by earnings before income taxes: +Year Ended September 30, +2017 +2016 +2015 +Computed income taxes at statutory rate +$ +12,750 +35.0 +% +$ +17,719 +35.0 +% +$ +19,264 +35.0 +% +Increase (decrease) in taxes resulting from - +State and local income taxes +1,093 +3.0 +1,329 +2.6 +1,365 +2.5 +Foreign tax rate differences +(281 +) +(0.8 +) +(337 +) +(0.7 +) +(217 +) +(0.4 +) +Qualified domestic production incentives +(1,012 +) +(2.8 +) +(1,290 +) +(2.5 +) +(1,197 +) +(2.2 +) +Acquisition-related costs +— +— +215 +0.4 +— +— +Uncertain tax position activity +134 +0.4 +122 +0.2 +(25 +) +— +Goodwill impairment charge +2,320 +6.4 +— +— +— +— +Valuation allowance +— +— +327 +0.7 +7 +— +Other, net +(132 +) +(0.4 +) +330 +0.7 +326 +0.6 +$ +14,872 +40.8 +% +$ +18,415 +36.4 +% +$ +19,523 +35.5 +% +(c) +The components of net deferred tax liabilities were as follows: +As of September 30, +2017 +2016 +Deferred tax assets - +Valuation reserves and non-deductible expenses +$ +1,762 +$ +2,366 +Stock compensation expense not deductible +3,367 +3,110 +Net operating loss and tax credit carryforwards +743 +2,190 +Basis difference in equity-method investee +302 +302 +Inventory basis differences +1,269 +1,620 +Other +(289 +) +297 +Subtotal +7,154 +9,885 +Less valuation allowance +(342 +) +(342 +) +Deferred tax assets +6,812 +9,543 +Deferred tax liabilities - +Fixed asset basis differences and depreciation +(1,325 +) +(1,526 +) +Intangible asset basis differences and amortization +(9,784 +) +(10,770 +) +Deferred tax liabilities +(11,109 +) +(12,296 +) +Net deferred tax liabilities +$ +(4,297 +) +$ +(2,753 +) +For income tax purposes, we have recorded deferred tax assets related to operating loss and tax credit carryforwards in both +U.S. and foreign jurisdictions totaling $546 and $197, respectively, as of September 30, 2017. At September 30, 2016, such deferred tax assets totaled $1,945 and $245, respectively. The operating loss carryforwards in foreign jurisdictions +have no expiration date. The operating loss carryforwards in the U.S. expire between 2023 and 2036 at the federal level, and between 2028 and 2036 at the state level. The aggregate amount of federal, state and foreign operating loss carryforwards +total $552, $2,731 and $697, respectively, at September 30, 2017, and the AMT tax credit carryforward totals $133. The use of the federal and state losses and credits is limited by the change of ownership provisions of the Internal Revenue +Code. +- 71 - +Table of Contents +The realization of deferred tax assets is dependent upon the generation of future taxable income in the +applicable jurisdictions. We have considered the levels of currently anticipated pre-tax income in U.S. and foreign jurisdictions in assessing the required level of the deferred tax asset valuation allowance +including the characterization of the income as ordinary or capital. Taking into consideration historical and current operating results, and other factors, we believe that it is more likely than not that the net deferred tax asset of $6,812 will be +realized. The amount of the net deferred tax asset considered realizable, however, could be reduced in future years if estimates of future taxable income are reduced. +Undistributed earnings reinvested indefinitely in our non-U.S. operations were approximately $12,500 and $10,000 at +September 30, 2017 and September 30, 2016, respectively. U.S. deferred tax liabilities of approximately $2,500 and $2,000 on such earnings, after consideration of foreign tax credits, have not been recorded as of September 30, 2017 +and September 30, 2016, respectively. +As described in Note 1, we utilize a comprehensive model for the recognition, measurement, presentation and +disclosure of uncertain tax positions, assuming full knowledge of all relevant facts by the applicable tax authorities. The total amount of unrecognized tax benefits at September 30, 2017 and September 30, 2016 related to such positions +was $517 and $502, respectively, of which $405 would favorably affect the effective tax rate if recognized. We generally recognize interest and penalties related to uncertain tax positions as a component of our income tax provision. During fiscal +2017, such penalties and interest totaled $35. During fiscal 2016, we increased our tax provision by approximately $8 for such penalties and interest, and recorded approximately $85 to the opening balance sheet of Magellan. We had approximately $165 +accrued for the payment of interest and penalties at September 30, 2017 compared to $130 accrued at September 30, 2016. The amount of our liability for uncertain tax positions expected to be paid or settled in the next 12 months is +uncertain. +A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: +2017 +2016 +Unrecognized income tax benefits beginning of year +$ +502 +$ +238 +Additions for tax positions of prior years +144 +264 +Tax examination and other settlements +(129 +) +— +Unrecognized income tax benefits at end of year +$ +517 +$ +502 +We are subject to examination by the tax authorities in the U.S. (both federal and state) and the countries of Australia, +Belgium, China, England, France, Germany, Holland, Italy and Singapore. In the U.S., open tax years are fiscal 2014, fiscal 2015 and fiscal 2016. In countries outside the U.S., open tax years generally range from fiscal 2012 and forward. However, in +Australia, Belgium and Singapore, the utilization of local net operating loss carryforwards extends the statute of limitations for examination well into the foreseeable future. To the extent that adjustments result from the completion of these +examinations or the lapsing of statutes of limitation, they will affect tax liabilities in the period known. We believe that the results of any tax authority examinations would not have a significant adverse impact on our financial condition or +results of operations +- 72 - +Table of Contents +(6) +Employee Benefits +(a) +Savings and Investment Plan - We have a profit sharing and retirement savings plan covering substantially all full-time U.S. employees. Profit sharing contributions to the plan, which are discretionary, are +approved by the board of directors. The plan permits participants to contribute to the plan through salary reduction. Under terms of the plan, we match 100% of an employee’s contributions, up to a maximum match of 4% of eligible compensation +(3% through December 31, 2016). Our discretionary and matching contributions to the plan amounted to approximately $1,912, $1,631 and $1,567, during fiscal 2017, 2016 and 2015, respectively. +(b) +Stock-Based Compensation Plans - During fiscal 2017, we had two active stock-based compensation plans, the 2004 Equity Compensation Plan, which became effective December 7, 2004, as amended (the “2004 +Plan”) and the 2012 Stock Incentive Plan, which became effective January 25, 2012 (the “2012 Plan”). +Each of the 2004 Plan and 2012 Plan authorized the granting of new shares for options, restricted shares or restricted share units for up to +3,000 shares, with the non-granted portion of the 2004 Plan permitted to be carried forward and added to the 2012 Plan authorized limit. As of September 30, 2017, we have granted 1,442 and 1,656 shares +under the 2004 Plan and 2012 Plan, respectively, thereby resulting in a remaining authorized limit of 2,902 shares. Options may be granted at exercise prices not less than 100% of the closing market value of the underlying common shares on the date +of grant and have maximum terms up to ten years. Vesting schedules for options, restricted shares and restricted share units are established at the time of grant and may be set based on future service periods, achievement of performance targets or a +combination thereof. All options contain provisions restricting their transferability and limiting their exercise in the event of termination of employment or the disability or death of the optionee. We recognize compensation expense for all +share-based payments made to employees, based upon the fair value of the share-based payment on the date of the grant. +During fiscal 2015, +we granted approximately 270 restricted share units (with a weighted-average grant date fair value of $17.91 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total +on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings target for fiscal 2015. While dividend equivalents were paid on these units throughout fiscal 2015, the target for fiscal 2015 +was not met and the performance-based portion of these restricted share units granted during fiscal 2015 were cancelled. +Additionally, +during fiscal 2015 in connection with the extension of an Amended and Restated Employment Agreement, we granted to our Chairman and Chief Executive Officer at that time (i) 25 restricted share units (with a grant date fair value of $16.50 per share) +to be earned only if specified revenue and earnings per share targets were achieved for fiscal 2015; and (ii) 100 time-vested options (with a weighted-average grant date fair value of $3.73 per share), with half vesting September 30, 2015 and +half vesting September 30, 2016. As a result of the fiscal 2015 performance targets being achieved, the restricted share units have been earned and the related compensation expense recorded in fiscal 2015. +During fiscal 2016, we granted approximately 370 restricted share units (with a weighted-average grant date fair value of $19.38 per share) to +certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to attainment of a specified earnings +target for fiscal 2016. While dividend equivalents were paid on these units throughout fiscal 2016, the target for fiscal 2016 was not met and the performance-based portion of these restricted share units granted during fiscal 2016 have been +cancelled. +- 73 - +Table of Contents +Additionally, during fiscal 2016 in connection with the Amended and Restated Employment Agreement +described above, we granted to our Chairman and Chief Executive Officer at that time, 25 restricted share units (with a grant date fair value of $17.03 per share) to be earned only if specified revenue and earnings per share targets were achieved +for fiscal 2016. As a result of the fiscal 2016 performance targets not being achieved, the restricted share units have been cancelled. +Similar to previous years, during fiscal 2017, we granted approximately 410 restricted share units (with a weighted-average grant date fair +value of $16.93 per share) to certain employees, generally with half of each employee’s grant being time-vested restricted share units vesting in total on the fourth anniversary of the grant date, and the remaining half being subject to +attainment of a specified earnings target for fiscal 2017. While dividend equivalents were paid on these units throughout fiscal 2017, the target for fiscal 2017 was not met and the performance-based portion of these restricted share units granted +during fiscal 2017 have been cancelled. +Additionally, during fiscal 2017 in connection with the Amended and Restated Employment Agreement, +we granted to our Chairman and Chief Executive Officer at the time, 25 restricted share units (with a grant date fair value of $19.09 per share) to be earned only if specified revenue and earnings per share targets were achieved for fiscal 2017. As +a result of the fiscal 2017 performance targets not being achieved, the restricted share units have been cancelled. +Giving effect to these +grants, cancellations and certain other activities for restricted shares and restricted share units throughout the years, including conversions to common shares, forfeitures, and new hire and employee promotion grants, approximately 550 restricted +share units remain outstanding as of September 30, 2017, with a weighted-average grant date fair value of $19.15 per share, a weighted-average remaining vesting period of 1.92 years and an aggregate intrinsic value of $7,859. The weighted-average grant date fair value of the approximate 91 restricted share units that vested during fiscal 2017 was $19.42 per share. +- 74 - +Table of Contents +The amount of stock-based compensation expense reported was $3,381, $2,911 and $3,324 in fiscal +2017, 2016 and 2015, respectively. The fiscal 2017 expense is comprised of $662 related to stock options and $2,719 related to restricted share units; the fiscal 2016 expense is comprised of $560 related to stock options and $2,351 related to +restricted share units; and the fiscal 2015 expense is comprised of $591 related to stock options and $2,733 related to restricted share units. The total income tax benefit recognized in the income statement for these stock-based compensation +arrangements was $861, $1,100 and $1,250, for fiscal 2017, 2016 and 2015, respectively. As of September 30, 2017, we expect future stock compensation expense for unvested options and unvested restricted share units to total $323 and $2,524, +respectively, which will be recognized during fiscal years 2018 through 2021. +We recognize compensation expense only for the portion of +shares that we expect to vest. As such, we apply estimated forfeiture rates to our compensation expense calculations. These rates have been derived using historical forfeiture data, stratified by several employee groups. During fiscal 2017, 2016 and +2015, we recorded $106, $76 and $86, respectively, in stock compensation expense to adjust estimated forfeiture rates to actual. +We have +elected to use the Black-Scholes option pricing model to determine grant-date fair value for stock options, with the following assumptions: (i) expected share price volatility based on the average of Meridian’s historical volatility over +the options’ expected lives and implied volatility based on the value of tradable call options; (ii) expected life of options based on contractual lives, employees’ historical exercise behavior and employees’ historical +post-vesting employment termination behavior; (iii) risk-free interest rates based on treasury rates that correspond to the expected lives of the options; and (iv) dividend yield based on the expected yield on underlying Meridian common +stock. +Year ended September 30, +2017 +2016 +2015 +Risk-free interest rates +1.34 +% +1.63 +% +2.07 +% +Dividend yield +4.1 +% +4.4 +% +3.7 +% +Life of option +6.44 yrs. +6.39 yrs. +6.33 yrs. +Share price volatility +27 +% +31 +% +33 +% +Forfeitures (by employee group) +0%-19 +% +0%-16 +% +0%-15 +% +- 75 - +Table of Contents +A summary of the status of our stock option plans as of September 30, 2017, and changes +during the year ended September 30, 2017, is presented in the table and narrative below: +Options +Wtd Avg +Exercise +Price +Wtd Avg +Remaining +Life (Yrs) +Aggregate +Intrinsic +Value +Outstanding beginning of period +780 +$ +20.97 +Grants +266 +16.38 +Exercises +(18 +) +16.54 +Forfeitures +(61 +) +18.34 +Cancellations +(25 +) +19.41 +Outstanding end of period +942 +$ +19.98 +6.51 +$ +120 +Exercisable end of period +661 +$ +21.04 +5.49 +$ +48 +A summary of the status of our nonvested options as of September 30, 2017, and changes during the year +ended September 30, 2017, is presented below: +Options +Weighted- +Average +Grant Date +Fair Value +Nonvested beginning of period +197 +$ +3.64 +Granted +266 +2.65 +Vested +(157 +) +3.15 +Cancelled +(25 +) +3.66 +Nonvested end of period +281 +$ +3.00 +The weighted average grant-date fair value of options granted was $2.65, $3.46 and $3.95 for fiscal 2017, 2016 +and 2015, respectively. The total intrinsic value of options exercised was $9, $616 and $850 for fiscal 2017, 2016 and 2015, respectively. The total grant-date fair value of options that vested during fiscal 2017, 2016 and 2015 was $494, $474 and +$571, respectively. +Cash received from options exercised was $302, $2,364 and $2,478 for fiscal 2017, 2016 and 2015, respectively. Tax +expense recorded to additional paid-in capital from option exercises totaled $431, $70 and $502 for fiscal 2017, 2016 and 2015, respectively. +In connection with the October 9, 2017 employment of the Company’s new Chief Executive Officer, in October 2017 we granted to our new +Chief Executive Officer (i) options to purchase 100 shares of common stock of the Company vesting on a pro rata basis over four years; and (ii) 13 restricted share units vesting 100% on the second anniversary of the grant. On November 8, +2017, we granted (i) 25 restricted share units vesting 100% on the fourth anniversary of the grant; and (ii) 25 restricted share units subject to attainment of a specified earnings target for fiscal 2018. +- 76 - +Table of Contents +(7) +Non-Current Liabilities +The Company has provided certain +post-employment benefits to its Executive Chairman (formerly Chairman and Chief Executive Officer) and its Chief Commercial Officer. These obligations total $1,680 and $1,628 at September 30, 2017 and 2016, respectively. In addition, we are +required by the governments of certain of the foreign countries in which we operate to maintain a level of reserves for potential future severance indemnity. These reserves total $652 and $565 at September 30, 2017 and 2016, respectively. +(8) +Reportable Segments and Major Concentration Data +Our reportable segments are Diagnostics and +Life Science. The Diagnostics segment consists of manufacturing operations for infectious disease products in Cincinnati, Ohio and, as a result of the acquisition of Magellan, manufacturing operations for products detecting elevated lead levels in +blood in Billerica, Massachusetts (near Boston), and the sale and distribution of diagnostics products domestically and abroad. The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, +England; Luckenwalde, Germany; and Sydney, Australia, and the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, nucleotides, competent cells, and bioresearch reagents domestically and abroad, including sales, business +development and distribution facilities in Singapore and Beijing, China to further pursue growing revenue opportunities in Asia. +Revenues from individual +customers constituting 10% or more of consolidated net revenues are as follows: +Year Ended September 30, +2017 +2016 +2015 +Customer A +$ +23,029 +(11 +)% +$ +20,246 +(10 +)% +$ +29,155 +(15 +)% +Customer B +$ +18,395 +(9 +)% +$ +19,585 +(10 +)% +$ +25,276 +(13 +)% +Accounts receivable from these two Diagnostics distributor customers accounted for 11% and 16% of consolidated accounts +receivable at September 30, 2017 and September 30, 2016, respectively. The Company’s international revenues totaled $61,936, $55,291 and $52,313 in fiscal years 2017, 2016 and 2015, respectively. Six of our product families – +C. difficile, foodborne, H. pylori , respiratory, women’s health & STD, and blood lead testing – accounted for 58%, 60% and 59% of consolidated net revenues in fiscal 2017, 2016 and 2015, respectively. We currently +purchase on a sole-source basis from a U.S. and an Italian manufacturer, respectively, the illumi pro -10 instruments on which our illumi gene molecular testing platform operates and the LeadCare instruments +used to test for blood lead levels. Additionally, two of our foodborne products sourced from another vendor accounted for 10%, 11% and 14% of third-party revenues for our Diagnostics segment in fiscal 2017, 2016 and 2015, respectively. +- 77 - +Table of Contents +Significant revenue information by country for the Diagnostics and Life Science segments is as follows. Revenues +are attributed to the geographic area based on the location to which the product is delivered. +Year Ended September 30, +2017 +2016 +2015 +United States +$ +118,342 +$ +120,826 +$ +120,599 +Italy +6,540 +6,599 +7,090 +Japan +1,913 +1,644 +2,603 +France +1,862 +1,605 +1,603 +United Kingdom +1,766 +1,991 +1,964 +Belgium +1,561 +1,501 +1,289 +Holland +1,240 +1,188 +1,326 +Other countries +10,297 +9,760 +9,640 +Total Diagnostics +$ +143,521 +$ +145,114 +$ +146,114 +Year Ended September 30, +2017 +2016 +2015 +United States +$ +20,493 +$ +19,965 +$ +21,918 +Germany +7,266 +6,982 +5,699 +United Kingdom +6,880 +6,410 +5,782 +China +5,862 +4,080 +2,526 +Australia +3,998 +3,153 +3,590 +France +2,739 +2,167 +2,026 +South Korea +2,425 +1,185 +406 +Japan +1,369 +1,320 +1,158 +Other countries +6,218 +5,706 +5,611 +Total Life Science +$ +57,250 +$ +50,968 +$ +48,716 +Identifiable assets for our Italian distribution organization were $7,712 and $8,782 at September 30, 2017 and 2016, +respectively. At September 30, 2017, identifiable assets for the Bioline Group’s operations in the U.K., Germany and Australia totaled approximately $15,755, $6,915 and $4,376, respectively; and totaled approximately $14,973, $7,024 and +$3,780, respectively, at September 30, 2016. +- 78 - +Table of Contents +Segment information for the years ended September 30, 2017, 2016 and 2015 is as follows: +Diagnostics +Life Science +Elim (1) +Total +Fiscal Year 2017 - +Net revenues – +Third-party +$ +143,521 +$ +57,250 +$ +— +$ +200,771 +Inter-segment +389 +537 +(926 +) +— +Operating income +23,086 +14,086 +210 +37,382 +Depreciation and amortization +7,037 +2,053 +— +9,090 +Capital expenditures +2,554 +1,913 +— +4,467 +Goodwill +35,213 +19,713 +— +54,926 +Other intangible assets +24,973 +1,731 +— +26,704 +Total assets +180,226 +69,938 +(387 +) +249,777 +Fiscal Year 2016 - +Net revenues – +Third-party +$ +145,114 +$ +50,968 +$ +— +$ +196,082 +Inter-segment +289 +893 +(1,182 +) +— +Operating income +38,202 +12,997 +179 +51,378 +Depreciation and amortization +5,471 +2,247 +— +7,718 +Capital expenditures +2,690 +1,314 +— +4,004 +Goodwill +42,608 +19,374 +— +61,982 +Other intangible assets +27,534 +2,321 +— +29,855 +Total assets +185,446 +66,624 +(42 +) +252,028 +Fiscal Year 2015 - +Net revenues – +Third-party +$ +146,114 +$ +48,716 +$ +— +$ +194,830 +Inter-segment +334 +1,300 +(1,634 +) +— +Operating income +44,136 +12,057 +(133 +) +56,060 +Depreciation and amortization +4,099 +2,510 +— +6,609 +Capital expenditures +3,112 +1,501 +— +4,613 +Goodwill +1,250 +21,099 +— +22,349 +Other intangible assets +2,364 +3,567 +— +5,931 +Total assets +119,939 +63,670 +(327 +) +183,282 +(1) +Eliminations consist of intersegment transactions. +A reconciliation of segment operating expenses to +consolidated earnings before income taxes for the years ended September 30, 2017, 2016 and 2015 is as follows: +Year Ended September 30, +2017 +2016 +2015 +Segment operating income +$ +37,382 +$ +51,378 +$ +56,060 +Interest income +171 +67 +23 +Interest expense +(1,642 +) +(897 +) +— +Other, net +518 +96 +(1,020 +) +Consolidated earnings before income taxes +$ +36,429 +$ +50,644 +$ +55,063 +Transactions between segments are accounted for at established intercompany prices for internal and management purposes with +all intercompany amounts eliminated in consolidation. +- 79 - +Table of Contents +(9) +Commitments and Contingencies +(a) +Royalty Commitments - We have entered into various license agreements that require payment of royalties based on a specified percentage of the sales of licensed products. Approximately 90% of our royalty expenses +relate to our Diagnostics operating segment, where the royalty rates range from 4% to 8%. These royalty expenses are recognized on an as-earned basis and recorded in the year earned as a component of cost of +sales. Annual royalty expenses associated with these agreements were approximately $2,600, $3,134 and $3,106 for the fiscal years ended September 30, 2017, 2016 and 2015, respectively. +(b) +Purchase Commitments - Excluding the operating lease commitments reflected in Note 9(c) below, we have purchase commitments primarily for inventory and service items as part of the normal course of +business. Commitments made under these obligations are $18,885, $1,935 and $944 for fiscal 2018, 2019 and 2020, respectively. No purchase commitments have been made beyond fiscal 2020. +(c) +Operating Lease Commitments - Meridian and its subsidiaries are lessees of (i) certain office and warehouse buildings in the U.S., Europe, Australia, Singapore and China; (ii) automobiles for use +by the direct sales forces in the U.S. and Europe; and (iii) certain office equipment such as facsimile and copier machines across all business units, under operating lease agreements that expire at various dates. Amounts charged to expense +under operating leases were $2,140, $1,966 and $1,797 for fiscal 2017, 2016 and 2015, respectively. Operating lease commitments for each of the five succeeding fiscal years are as follows: fiscal 2018 - $1,978; fiscal 2019 - $1,325; fiscal 2020 +- $609; fiscal 2021 - $490; and fiscal 2022 - $426. +(d) +Litigation - We are a party to various litigation matters from time to time that we believe are in the normal course of business. The ultimate resolution of these matters is not expected to have a material +adverse effect on our financial position, results of operations or cash flows. See Item 3. “Legal Proceedings” for a discussion of the status of certain litigation related to our intellectual property. +(e) +Indemnifications - In conjunction with certain contracts and agreements, we provide routine indemnifications related to our performance obligations. The terms of these indemnifications range in duration and in +some circumstances are not explicitly defined. The maximum obligation under some such indemnifications is not explicitly stated and, as a result of our having no history of paying such indemnifications, cannot be reasonably estimated. We have not +made any payments for these indemnifications and no liability is recorded at September 30, 2017 or September 30, 2016. We believe that if we were to incur a loss on any of these matters, the loss would not have a material effect on our +financial condition. +- 80 - +Table of Contents +(10) +Quarterly Financial Data (Unaudited) +The sum of the earnings per common share may not equal the +corresponding annual amounts due to interim quarter rounding. +For the Quarter Ended in Fiscal 2017 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +46,809 +$ +54,125 +$ +50,140 +$ +49,697 +Gross profit +29,450 +33,531 +31,197 +30,655 +Net earnings +6,279 +9,312 +240 +5,726 +Basic earnings per common share +0.15 +0.22 +0.01 +0.14 +Diluted earnings per common share +0.15 +0.22 +0.01 +0.13 +Cash dividends per common share +0.20 +0.125 +0.125 +0.125 +For the Quarter Ended in Fiscal 2016 +December 31 +March 31 +June 30 +September 30 +Net revenues +$ +47,160 +$ +51,259 +$ +50,665 +$ +46,998 +Gross profit +31,583 +33,572 +32,909 +29,723 +Net earnings +8,893 +9,091 +8,754 +5,491 +Basic earnings per common share +0.21 +0.22 +0.21 +0.13 +Diluted earnings per common share +0.21 +0.21 +0.21 +0.13 +Cash dividends per common share +0.20 +0.20 +0.20 +0.20 +(11) +Subsequent Events +On November 15, 2017, a class action complaint was filed naming Meridian, its +Chief Executive Officer and its Chief Financial Officer (in their capacities as such) as defendants. The complaint alleges that Meridian made false and misleading representations concerning certain lead test systems used by Magellan at or around the +time of Meridian’s acquisition of Magellan and subsequent thereto. The lawsuit underlying plaintiff’s class action complaint seeks compensatory damages, injunctive relief and attorneys’ fees to all members of the proposed class. +Because the litigation and related discovery are in preliminary stages, we do not have sufficient information to determine or predict the ultimate outcome or estimate the range of possible losses, if any. Accordingly, no provision for litigation +losses has been included within these Consolidated Financial Statements for fiscal 2017. +- 81 - +Table of Contents +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE +Not applicable. +ITEM +9A. +CONTROLS AND PROCEDURES +(a) +Evaluation of Disclosure Controls and Procedures +The term “disclosure controls and procedures” as defined by Rule 13a-15(e) of the +Securities Exchange Act of 1934, as amended (the “Exchange Act”) refers to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under +the Exchange Act is recorded, processed, summarized and reported within required time periods. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is +accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +In accordance with Exchange Act Rule 13a-15(b), Meridian’s management, with the participation of the Chief Executive Officer and Chief Financial Officer, +conducted an evaluation of the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2017. In conducting this evaluation, Meridian concluded there is a material weakness in the design and operating effectiveness +of its internal control over financial reporting, as described below. As a result of such evaluation and this conclusion, Meridian also has concluded that its disclosure controls and procedures were not effective in providing reasonable assurance +that information required to be disclosed in our reports filed under the Exchange Act was recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information was accumulated and +communicated to our management to allow timely decisions regarding required disclosure. +Meridian’s management does not expect that its disclosure +controls and procedures will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the +design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can +provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur due to simple +errors or mistakes. The design of any system of controls is based in part upon certain assumptions regarding the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all +potential future conditions. +- 82 - +Table of Contents +(b) Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). +The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in +reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, +we conducted an evaluation of the effectiveness of our internal control over financial reporting as of September 30, 2017, based on the framework and criteria in the 2013 Internal Control—Integrated Framework, issued by the Committee of +Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, we concluded that the Company’s internal control over financial reporting was not effective as of September 30, 2017 for the reasons described below. +During the course of completing this evaluation we identified deficiencies related to Information Technology General Controls (“ITGC”) intended to +restrict access to certain data and applications, resulting in inappropriate access at both the Information Technology and end user levels within an application impacting financial reporting functions and controls. +A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable +possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Although no material misstatements were identified in our consolidated financial statements, these control +deficiencies create a reasonable possibility that a material misstatement of our consolidated financial statements will not be prevented or detected on a timely basis. We have concluded that these identified deficiencies, when aggregated, constitute +a material weakness in internal control over financial reporting. +- 83 - +Table of Contents +Item 8 includes the adverse audit report of the Company’s independent registered public accounting firm on +Meridian’s internal control over financial reporting as of September 30, 2017. +(c) Changes in Internal Control over Financial Reporting +There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially +affect, Meridian’s internal control over financial reporting, except as otherwise described in this Item 9A. +(d) Remediation of the Material +Weakness +We have begun remediation efforts to address the control deficiencies identified, which gave rise to the material weakness noted above. We +are performing a comprehensive review of the financial reporting application in which the control deficiencies were identified in order to further restrict access and improve authorization protocols. Our objective is to complete remediation efforts +in fiscal 2018. +ITEM 9B. +OTHER INFORMATION +Not applicable. +PART III. +The information required by Items 10, 11, 12 (other than that portion set forth below), 13 and 14, of Part III are incorporated by +reference from the Registrant’s Proxy Statement for its 2018 Annual Shareholders’ Meeting to be filed with the Commission pursuant to Regulation 14A. +- 84 - +Table of Contents +ITEM 12. +EQUITY COMPENSATION PLAN INFORMATION +The +following table presents summary information as of September 30, 2017 with respect to all of our equity compensation plans (number of securities information in thousands). +Plan Category +(a) +Number of +Securities to be +issued upon +exercise of +outstanding +options, warrants +and rights +(b) +Weighted- +average exercise +price of +outstanding +options, +warrants +and +rights +(c) +Number of securities +remaining available +for future issuance +under equity +compensation +plans +(excluding securities +reflected in column +(a)) +Equity compensation plans approved by security holders (1) +942 +$ +19.975 +2,902 +Total (2) +942 +$ +19.975 +2,902 +(1) +2004 Equity Compensation Plan, as amended +2012 Stock Incentive Plan +(2) +Weighted-average remaining term of 6.51 years +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) +(1) and (2) FINANCIAL STATEMENTS AND SCHEDULES. +All financial statements and schedules required to be +filed by Item 8 of this Form and included in this report have been so identified under Item 8. No additional financial statements or schedules are being filed since the requirements of paragraph (c) under Item 15 are not applicable to Meridian. +(b) +(3) EXHIBITS. +Exhibit +Number +Description of Exhibit +3.1 +Articles of Incorporation, including amendments not related to Company name change (Incorporated by reference to Registration Statement No. 333-02613 on Form S-3 filed with the Securities and Exchange Commission on April +18, 1996 and Meridian’s Form 8-K filed with the Securities and Exchange Commission on May 16, 2007) +3.2 +Amended Code of Regulations (Incorporated by reference to Meridian’s Form 8-K filed with the Securities +and Exchange Commission on November 13, 2012) +10.1* +Amendment No. 1 to Supplemental Benefit Agreement Dated September +23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on September 25, 2014) +- 85 - +Table of Contents +10.2* +Third Amended and Restated Employment Agreement Dated October +3, 2016 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on October 5, 2016) +10.3* +Letter Agreement Dated July +26, 2016 between Meridian and Richard L. Eberly (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2016) +10.4* +Executive Employment Agreement dated March +21, 2016 between Meridian and Amy Winslow (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2016) +10.5* +Employment Agreement dated October 9, 2017 between Meridian and John P. Kenny (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission on October 11, 2017) +10.6* +Dividend Reinvestment Plan (Incorporated by reference to Meridian’s Annual Report on Form 10-K for +the Fiscal Year Ended September 30, 1999) +10.7* +2004 Equity Compensation Plan, amended and restated effective January +25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.8* +2012 Stock Incentive Plan, effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.9* +Fiscal 2018 Cash-Based Incentive Compensation Plan-Officers and Selected Executives (Filed herewith) +10.10* +Form of Time-Based Restricted Share Unit Award Agreement dated November 8, 2017 (Filed herewith) +10.11* +Form of Performance Award Restricted Share Unit Award Agreement dated November 8, 2017 (Filed herewith) +10.12* +Form of Time-Based Nonqualified Stock Option Award Agreement dated November 8, 2017 (Filed herewith) +10.13* +Form of Performance Award Nonqualified Stock Option Award Agreement dated November 8, 2017 (Filed herewith) +10.14* +Form of Meridian Bioscience, Inc. Change in Control Agreement dated August +4, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2016) +10.15 +Agreement and Plan of Merger among Meridian Bioscience, Inc., Mariner Merger Sub, Inc., Magellan Biosciences, Inc. and Ampersand 2006 Limited +Partnership as the Stockholder Representative dated as of March 24, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2016) +10.16 +Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc. Meridian Life Science, +Inc. and Fifth Third Bank dated August 1, 2007 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2007) +- 86 - +Table of Contents +10.16.1 +Term Note among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc. Meridian Life Science, Inc., Bioline USA, +Inc. and Fifth Third Bank dated March 22, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended March 31, 2016) +10.16.2 +Amended and Restated Revolving Note with Fifth Third Bank dated March +22, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended March 31, 2016) +10.16.3 +First Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., +Meridian Life Science, Inc. and Fifth Third Bank dated September 2, 2010 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2010) +10.16.4 +Second Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., +Meridian Life Science, Inc. and Fifth Third Bank dated December 1, 2010 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended December 31, 2010) +10.16.5 +Third Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian +Life Science, Inc. and Fifth Third Bank dated September 15, 2012 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2012) +10.16.6 +Fifth Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian +Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank dated April 21, 2015 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended June 30, +2015) +10.16.7 +Sixth Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian +Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank dated March 22, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Fiscal Quarter Ended March 31, +2016) +10.16.8 +Seventh Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank +dated February 6, 2017 (Filed herewith) +10.16.9 +Eighth Amendment to Loan and Security Agreement among Meridian Bioscience, Inc., Meridian Bioscience Corporation, Omega Technologies, Inc., Meridian Life Science, Inc., Bioline USA, Inc. and Fifth Third Bank +dated July 20, 2017 (Filed herewith) +13 +2017 Annual Report to Shareholders (1) +14 +Code of Ethics (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal +Year Ended September 30, 2003) +21 +Subsidiaries of the Registrant (Filed herewith) +23 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +31.1 +Certification of Principal Executive Officer required by Rule 13a-14(a) (Filed herewith) +31.2 +Certification of Principal Financial Officer required by Rule 13a-14(a) (Filed herewith) +- 87 - +Table of Contents +32 +Section 1350 Certification of Chief Executive Officer and Chief Financial Officer (Filed herewith) +101 +The following financial information from Meridian Bioscience Inc.’s Annual Report on Form 10-K for the fiscal year ended September 30, 2017 filed with the SEC on November 29, +2017, formatted in XBRL includes: (i) Consolidated Statements of Operations for the years ended September 30, 2017, 2016 and 2015; (ii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2017, 2016 and +2015; (iii) Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016 and 2015; (iv) Consolidated Balance Sheets as of September 30, 2017 and 2016; (v) Consolidated Statements of Shareholders’ Equity for the +years ended September 30, 2017, 2016 and 2015; and (vi) the Notes to Consolidated Financial Statements +* +Management Compensatory Contracts +(1) +Only specific portions of the 2017 Annual Report to Shareholders are incorporated by reference in this Form 10-K as filed herewith. A supplemental paper copy of the 2017 Annual +Report to Shareholders has been furnished to the Securities and Exchange Commission for informational purposes only or will be posted on our website, www.meridianbioscience.com . +Meridian will provide shareholders with any exhibit upon the payment of a specified reasonable fee, which fee shall be limited to Meridian’s reasonable +expenses in furnishing such exhibit. +ITEM 16. +FORM 10-K SUMMARY +None. +- 88 - +Table of Contents +SIGNATURES +Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its +behalf by the undersigned, thereunto duly authorized. +MERIDIAN BIOSCIENCE, INC. +By: +/s/ Jack Kenny +Date: November 29, 2017 +Jack Kenny +Chief Executive Officer +We, the undersigned directors and officers of the Registrant, hereby severally constitute Jack Kenny and Melissa A. +Lueke, and each of them singly, our true and lawful attorneys with full power to them and each of them to sign for us, in our names in the capacities indicated below, any and all amendments to the Annual Report on Form +10-K filed with the Securities and Exchange Commission. +Pursuant to the requirements of the Securities Exchange +Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. +Signature +Capacity +Date +/s/ Jack Kenny +Jack Kenny +Chief Executive Officer and Director +November 29, 2017 +/s/ Melissa A. Lueke +Melissa A. Lueke +Executive Vice President, Chief Financial Officer, and Secretary (Principal Financial and Accounting Officer) +November 29, 2017 +/s/ John A. Kraeutler +John A. Kraeutler +Executive Chairman of the Board +November 29, 2017 +/s/ James M. Anderson +James M. Anderson +Director +November 29, 2017 +/s/ Dwight E. Ellingwood +Dwight E. Ellingwood +Director +November 29, 2017 +/s/ John C. McIlwraith +John C. McIlwraith +Director +November 29, 2017 +/s/ David C. Phillips +David C. Phillips +Director +November 29, 2017 +/s/ John M. Rice, Jr. +John M. Rice, Jr. +Director +November 29, 2017 +/s/ Catherine A. Sazdanoff +Catherine A. Sazdanoff +Director +November 29, 2017 +- 89 - +Table of Contents +SCHEDULE II +Meridian Bioscience, Inc. +and +Subsidiaries +Valuation and Qualifying Accounts +(Dollars in thousands) +Years Ended +September 30, 2017, 2016 and 2015 +Description +Balance at +Beginning +of Period +Charged to +Costs and +Expenses +Deductions +Other (a) +Balance at +End of +Period +Year Ended September 30, 2017: +Allowance for doubtful accounts +$ +334 +$ +90 +$ +(134 +) +$ +17 +$ +307 +Inventory realizability reserves +2,680 +35 +(661 +) +5 +2,059 +Valuation allowances – deferred taxes +342 +— +— +— +342 +Year Ended September 30, 2016: +Allowance for doubtful accounts +$ +248 +$ +139 +$ +(69 +) +$ +16 +$ +334 +Inventory realizability reserves +2,456 +1,285 +(1,072 +) +11 +2,680 +Valuation allowances – deferred taxes +15 +327 +— +— +342 +Year Ended September 30, 2015: +Allowance for doubtful accounts +$ +272 +$ +73 +$ +(41 +) +$ +(56 +) +$ +248 +Inventory realizability reserves +2,942 +208 +(590 +) +(104 +) +2,456 +Valuation allowances – deferred taxes +8 +7 +— +— +15 +(a) +Balances reflect the effects of currency translation and in 2016, the acquisition of Magellan. +- 90 - \ No newline at end of file diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/filing_metadata.csv b/raw/filings/0000794172/2017/0001193125-17-354808/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..2d80c7c14b88daa122e87bcd5e3a3254bb11a846 --- /dev/null +++ b/raw/filings/0000794172/2017/0001193125-17-354808/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000794172,VIVO,MERIDIAN BIOSCIENCE INC,10-K,2017-11-29,2017-09-30,2017-11-29T13:49:08.000Z,0001193125-17-354808,d472698d10k.htm,ANNUAL REPORT,6414635,1,0,https://www.sec.gov/Archives/edgar/data/794172/000119312517354808/d472698d10k.htm,https://www.sec.gov/Archives/edgar/data/794172/000119312517354808/,2017,2017,1 diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/item1.txt b/raw/filings/0000794172/2017/0001193125-17-354808/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..86cc5305b3ea1da017bf11f3672e8a449b01e9a5 --- /dev/null +++ b/raw/filings/0000794172/2017/0001193125-17-354808/item1.txt @@ -0,0 +1,23 @@ +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in (i) the development, manufacture, sale and distribution of +diagnostic test kits, primarily for certain gastrointestinal, viral, respiratory, and parasitic infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, PCR/qPCR reagents, +nucleotides, competent cells, and bioresearch reagents used by researchers and other diagnostic manufacturers. The Company was incorporated in Ohio in 1976. Our principal corporate offices are located near Cincinnati, Ohio, USA. +During March 2016, we acquired all of the outstanding common stock of Magellan Biosciences, Inc., and its wholly-owned subsidiary Magellan Diagnostics, Inc. +(collectively, “Magellan”), which is now reported as part of our Diagnostics operating segment. Headquartered near Boston, Massachusetts, Magellan is a leading manufacturer of products cleared by the Food & Drug Administration +(“FDA”) for the point-of-care testing of capillary blood to diagnose lead poisoning in children and adults. Further details of the Magellan acquisition are set +forth in Note 2 of the accompanying Consolidated Financial Statements. +- 5 - +Table of Contents +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments thereto, free of charge through this website, as +soon as reasonably practicable after such material has been electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). These reports may also be read and copied at the SEC’s public reference room at 100 +F Street, N.E., Washington, DC 20549, phone number 1-800-732-0330. The SEC maintains an internet site containing these filings +and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered part of this Annual Report on Form 10-K. +Reportable Segments +Our reportable segments are +Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. Detailed information related to the reportable segments can be found in the following locations within this Annual Report on Form +10-K: +Type of Segment Information +Location within Annual Report on Form 10-K +Physical locations and activities \ No newline at end of file diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/item13.txt b/raw/filings/0000794172/2017/0001193125-17-354808/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..c09303c7945ea7eaa193446bc8c8944747eff14b --- /dev/null +++ b/raw/filings/0000794172/2017/0001193125-17-354808/item13.txt @@ -0,0 +1,3 @@ +Item 13 +Certain Relationships and Related Transactions, and Director Independence +84 \ No newline at end of file diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/item9a.txt b/raw/filings/0000794172/2017/0001193125-17-354808/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..5e7761b5d8c7938f4978e09b4b16fa16d9c55c9e --- /dev/null +++ b/raw/filings/0000794172/2017/0001193125-17-354808/item9a.txt @@ -0,0 +1,3 @@ +Item 9A +Controls and Procedures +82 \ No newline at end of file diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/rp_note.txt b/raw/filings/0000794172/2017/0001193125-17-354808/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000794172/2017/0001193125-17-354808/rpt_disclosure.txt b/raw/filings/0000794172/2017/0001193125-17-354808/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..c5936b2761b68fd3791caab01b24e4d047cf7e1b --- /dev/null +++ b/raw/filings/0000794172/2017/0001193125-17-354808/rpt_disclosure.txt @@ -0,0 +1,16 @@ +TRANSACTIONS WITH RELATED PERSONS +During fiscal 2018, the Company leased certain office space from an entity controlled by Marco G. Calzavara, who served as President and Managing Director, Meridian Bioscience Europe through July +2018. Payments made under such arrangements during fiscal 2018 totaled approximately $160,000. +Nasdaq rules require the Company to +conduct an appropriate review of related party transactions required to be disclosed by the Company pursuant to SEC Regulation S-K Item 404 for potential conflict of interest situations on an ongoing basis and +that all such transactions must be approved by the Audit Committee or another Committee comprised of independent Directors. As a result, the Audit Committee annually reviews all such related party transactions and approves each related party +transaction if it determines that it is in the best interests of the Company. Additionally, the Audit Committee’s Charter provides it the authority to review, approve and monitor transactions involving the Company and “related +persons” (Directors and Executive Officers or their immediate family members, or shareholders owning five percent or greater of the Company’s outstanding stock). This also covers any related person transaction that meets the minimum +threshold for disclosure in the proxy statement under +14 +Table of Contents +the relevant SEC rules (generally, transactions involving amounts exceeding $120,000 in which a related person has a direct or indirect material interest). In considering +the transaction, the Audit Committee may consider all relevant factors, including, as applicable: (i) the Company’s business rationale for entering into the transaction; (ii) the alternatives to entering into a related person +transaction; (iii) whether the transaction is on terms comparable to those available to third parties, or in the case of employment relationships, to employees generally; (iv) the potential for the transaction to lead to an actual or +apparent conflict of interest and any safeguards imposed to prevent such actual or apparent conflicts; and (v) the overall fairness of the transaction to the Company. This policy is included in the Company’s Employee Handbook. The +approvals of such related person transactions are evidenced by internal Company resolutions, minutes or memoranda. \ No newline at end of file diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/filing.txt b/raw/filings/0000794172/2021/0001193125-21-337663/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e6b8ffb9ab2156f3799c1e0505525412cc0a90af --- /dev/null +++ b/raw/filings/0000794172/2021/0001193125-21-337663/filing.txt @@ -0,0 +1,4282 @@ +10-K +2 Yes false FY 0000794172 --09-30 Yes No Yes 0000794172 2020-10-01 2021-09-30 0000794172 2019-10-01 2020-09-30 0000794172 2018-10-01 2019-09-30 0000794172 2020-09-30 0000794172 2021-09-30 0000794172 2019-09-30 0000794172 2021-03-31 0000794172 2021-10-31 0000794172 2020-04-30 0000794172 2021-02-01 2021-02-01 0000794172 2021-02-01 0000794172 2021-07-01 0000794172 2018-09-30 0000794172 vivo:OtherCountriesMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember country:JP 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember country:NL 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember country:BE 2019-10-01 2020-09-30 0000794172 country:GB vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember country:FR 2019-10-01 2020-09-30 0000794172 country:IT vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 country:US vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 country:KR vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:AU vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:IT vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:TR vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:JP vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:IN vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:ID vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember country:NL 2019-10-01 2020-09-30 0000794172 vivo:OtherCountriesMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:FR vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:ES vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:GB vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:CN vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:FI vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:DE vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember country:US 2019-10-01 2020-09-30 0000794172 country:FI vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember country:CA 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 srt:ConsolidationEliminationsMember 2019-10-01 2020-09-30 0000794172 us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2019-10-01 2020-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2019-10-01 2020-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2019-10-01 2020-09-30 0000794172 vivo:ConsolidationEliminationMember 2019-10-01 2020-09-30 0000794172 vivo:Covid19ProductsMember vivo:LifeScienceSegmentMember us-gaap:ProductConcentrationRiskMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 us-gaap:ProductConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:Covid19ProductsMember vivo:ConsolidatedRevenueMember 2019-10-01 2020-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ThreeDiagnosticsProductFamiliesMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:OneOfTheDiagnositicOrLifeScienceSegmentCustomerMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember us-gaap:CustomerConcentrationRiskMember vivo:OneSingleCustomerMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember srt:MinimumMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember vivo:VivoCustomerFMemberMember vivo:VivoLifeScienceMember 2019-10-01 2020-09-30 0000794172 us-gaap:CorporateMember 2019-10-01 2020-09-30 0000794172 vivo:ForeignCustomersMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 vivo:CustomerAMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 vivo:CustomerBMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 vivo:CustomerCMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerDMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerEMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerFMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 srt:ChiefExecutiveOfficerMember vivo:AmendedAndRestatedEmploymentAgreementMember 2019-10-01 2020-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2019-10-01 2020-09-30 0000794172 us-gaap:CommonStockMember 2019-10-01 2020-09-30 0000794172 us-gaap:RetainedEarningsMember 2019-10-01 2020-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2019-10-01 2020-09-30 0000794172 vivo:AmendedAndRestatedEmploymentAgreementMember srt:ChiefExecutiveOfficerMember us-gaap:RestrictedStockUnitsRSUMember 2019-10-01 2020-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-10-01 2020-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember srt:AmericasMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember us-gaap:EMEAMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember vivo:OtherForeignMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:OtherForeignMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember us-gaap:EMEAMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember srt:AmericasMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember vivo:MolecularReagentsMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember vivo:ImmunologicalReagentsMember 2019-10-01 2020-09-30 0000794172 vivo:NonMolecularAssaysMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:MolecularAssaysMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:OtherDiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:BloodChemistryAssaysMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:RespiratoryIllnessAssaysMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:GastrointestinalAssaysMember 2019-10-01 2020-09-30 0000794172 vivo:BreathtekmemberMember 2019-10-01 2020-09-30 0000794172 vivo:ExalenzAndGenepocMember 2019-10-01 2020-09-30 0000794172 vivo:ExalenzMember 2019-10-01 2020-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2019-10-01 2020-09-30 0000794172 vivo:DOJSubpoenaMember 2019-10-01 2020-09-30 0000794172 vivo:LeaseElementsMember vivo:ReagentRentalArrangementsMember us-gaap:ProductConcentrationRiskMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 vivo:GenepocIncMember 2019-10-01 2020-09-30 0000794172 us-gaap:CostOfSalesMember 2019-10-01 2020-09-30 0000794172 us-gaap:OperatingExpenseMember 2019-10-01 2020-09-30 0000794172 srt:MinimumMember 2019-10-01 2020-09-30 0000794172 srt:MaximumMember 2019-10-01 2020-09-30 0000794172 srt:MinimumMember 2020-10-01 2021-09-30 0000794172 srt:MaximumMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:OtherCountriesMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember country:JP 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember country:NL 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember country:BE 2020-10-01 2021-09-30 0000794172 country:GB vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember country:FR 2020-10-01 2021-09-30 0000794172 country:IT vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 country:US vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 country:AU vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:IT vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:TR vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:JP vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:IN vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:ID vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:NL vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:OtherCountriesMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:KR vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:FR vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:ES vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:GB vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:CN vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:FI vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:DE vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember country:US 2020-10-01 2021-09-30 0000794172 country:FI vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember country:CA 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 srt:ConsolidationEliminationsMember 2020-10-01 2021-09-30 0000794172 us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2020-10-01 2021-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2020-10-01 2021-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2020-10-01 2021-09-30 0000794172 vivo:ConsolidationEliminationMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceSegmentMember vivo:Covid19ProductsMember us-gaap:ProductConcentrationRiskMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 us-gaap:ProductConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:Covid19ProductsMember vivo:ConsolidatedRevenueMember 2020-10-01 2021-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ThreeDiagnosticsProductFamiliesMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:OneOfTheDiagnositicOrLifeScienceSegmentCustomerMember 2020-10-01 2021-09-30 0000794172 vivo:OneSingleCustomerMember us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember vivo:VivoCustomerAMemberMember vivo:VivoDiagnosticsMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember vivo:VivoCustomerFMemberMember vivo:VivoLifeScienceMember 2020-10-01 2021-09-30 0000794172 srt:MinimumMember us-gaap:BuildingAndBuildingImprovementsMember 2020-10-01 2021-09-30 0000794172 srt:MaximumMember us-gaap:BuildingAndBuildingImprovementsMember 2020-10-01 2021-09-30 0000794172 srt:MinimumMember us-gaap:MachineryAndEquipmentMember 2020-10-01 2021-09-30 0000794172 us-gaap:MachineryAndEquipmentMember srt:MaximumMember 2020-10-01 2021-09-30 0000794172 srt:MinimumMember us-gaap:ComputerEquipmentMember 2020-10-01 2021-09-30 0000794172 srt:MaximumMember us-gaap:ComputerEquipmentMember 2020-10-01 2021-09-30 0000794172 vivo:InstrumentsUnderCustomerReagentRentalArrangementsMember 2020-10-01 2021-09-30 0000794172 us-gaap:LeaseholdImprovementsMember 2020-10-01 2021-09-30 0000794172 us-gaap:CorporateMember 2020-10-01 2021-09-30 0000794172 vivo:ForeignCustomersMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 vivo:CustomerAMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 vivo:CustomerBMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 vivo:CustomerCMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerDMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerEMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerFMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 vivo:StockIncentivePlanTwentyTwentyOneMember 2020-10-01 2021-09-30 0000794172 us-gaap:DomesticCountryMember 2020-10-01 2021-09-30 0000794172 us-gaap:StateAndLocalJurisdictionMember 2020-10-01 2021-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2020-10-01 2021-09-30 0000794172 vivo:StockIncentivePlanMember 2020-10-01 2021-09-30 0000794172 us-gaap:CommonStockMember 2020-10-01 2021-09-30 0000794172 us-gaap:RetainedEarningsMember 2020-10-01 2021-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2020-10-01 2021-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2020-10-01 2021-09-30 0000794172 us-gaap:ForeignCountryMember 2020-10-01 2021-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember srt:AmericasMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember us-gaap:EMEAMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember vivo:OtherForeignMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:OtherForeignMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember us-gaap:EMEAMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember srt:AmericasMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember vivo:MolecularReagentsMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember vivo:ImmunologicalReagentsMember 2020-10-01 2021-09-30 0000794172 vivo:NonMolecularAssaysMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:MolecularAssaysMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:OtherDiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:BloodChemistryAssaysMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:RespiratoryIllnessAssaysMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:GastrointestinalAssaysMember 2020-10-01 2021-09-30 0000794172 vivo:ExalenzMember 2020-10-01 2021-09-30 0000794172 vivo:BreathtekmemberMember 2020-10-01 2021-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2020-10-01 2021-09-30 0000794172 vivo:BreathIdProductsMember 2020-10-01 2021-09-30 0000794172 vivo:DOJSubpoenaMember 2020-10-01 2021-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ReagentRentalArrangementsMember vivo:LeaseElementsMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 vivo:GenepocIncMember 2020-10-01 2021-09-30 0000794172 vivo:BreathtekmemberMember us-gaap:CustomerRelationshipsMember 2020-10-01 2021-09-30 0000794172 us-gaap:CostOfSalesMember 2020-10-01 2021-09-30 0000794172 us-gaap:OperatingExpenseMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:OtherCountriesMember vivo:DiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember country:JP 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember country:NL 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember country:BE 2018-10-01 2019-09-30 0000794172 country:GB vivo:DiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember country:FR 2018-10-01 2019-09-30 0000794172 country:IT vivo:DiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember country:US 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember country:US 2018-10-01 2019-09-30 0000794172 country:DE vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:FI vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:CN vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:GB vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:ES vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:FR vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 vivo:OtherCountriesMember vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:NL vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:ID vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:IN vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:JP vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:TR vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:IT vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:AU vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:KR vivo:LifeScienceMember 2018-10-01 2019-09-30 0000794172 country:FI vivo:DiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember country:CA 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2018-10-01 2019-09-30 0000794172 srt:ConsolidationEliminationsMember 2018-10-01 2019-09-30 0000794172 us-gaap:OperatingSegmentsMember 2018-10-01 2019-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2018-10-01 2019-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2018-10-01 2019-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2018-10-01 2019-09-30 0000794172 vivo:ConsolidationEliminationMember 2018-10-01 2019-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ThreeDiagnosticsProductFamiliesMember us-gaap:SalesRevenueNetMember 2018-10-01 2019-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:OneOfTheDiagnositicOrLifeScienceSegmentCustomerMember 2018-10-01 2019-09-30 0000794172 us-gaap:SalesRevenueNetMember us-gaap:CustomerConcentrationRiskMember vivo:OneSingleCustomerMember 2018-10-01 2019-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember us-gaap:OperatingSegmentsMember 2018-10-01 2019-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember 2018-10-01 2019-09-30 0000794172 us-gaap:RetainedEarningsMember 2018-10-01 2019-09-30 0000794172 us-gaap:CorporateMember 2018-10-01 2019-09-30 0000794172 vivo:ForeignCustomersMember us-gaap:SalesRevenueNetMember 2018-10-01 2019-09-30 0000794172 vivo:CustomerAMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2018-10-01 2019-09-30 0000794172 vivo:CustomerBMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2018-10-01 2019-09-30 0000794172 vivo:CustomerCMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2018-10-01 2019-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerDMember us-gaap:CustomerConcentrationRiskMember 2018-10-01 2019-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerEMember us-gaap:CustomerConcentrationRiskMember 2018-10-01 2019-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerFMember us-gaap:CustomerConcentrationRiskMember 2018-10-01 2019-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2018-10-01 2019-09-30 0000794172 us-gaap:CommonStockMember 2018-10-01 2019-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2018-10-01 2019-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2018-10-01 2019-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember srt:AmericasMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember us-gaap:EMEAMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember vivo:OtherForeignMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember vivo:OtherForeignMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember us-gaap:EMEAMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember srt:AmericasMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember vivo:MolecularReagentsMember 2018-10-01 2019-09-30 0000794172 vivo:LifeScienceMember vivo:ImmunologicalReagentsMember 2018-10-01 2019-09-30 0000794172 vivo:NonMolecularAssaysMember vivo:DiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember vivo:MolecularAssaysMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember vivo:OtherDiagnosticsMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember vivo:BloodChemistryAssaysMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember vivo:RespiratoryIllnessAssaysMember 2018-10-01 2019-09-30 0000794172 vivo:DiagnosticsMember vivo:GastrointestinalAssaysMember 2018-10-01 2019-09-30 0000794172 vivo:ExalenzAndGenepocMember 2018-10-01 2019-09-30 0000794172 us-gaap:RetainedEarningsMember us-gaap:AccountingStandardsUpdate201409Member srt:RevisionOfPriorPeriodAccountingStandardsUpdateAdjustmentMember 2018-10-01 2019-09-30 0000794172 us-gaap:AccountingStandardsUpdate201409Member srt:RevisionOfPriorPeriodAccountingStandardsUpdateAdjustmentMember 2018-10-01 2019-09-30 0000794172 us-gaap:RetainedEarningsMember us-gaap:AccountingStandardsUpdate201802Member srt:RevisionOfPriorPeriodAccountingStandardsUpdateAdjustmentMember 2018-10-01 2019-09-30 0000794172 us-gaap:AccountingStandardsUpdate201802Member us-gaap:AccumulatedOtherComprehensiveIncomeMember srt:RevisionOfPriorPeriodAccountingStandardsUpdateAdjustmentMember 2018-10-01 2019-09-30 0000794172 vivo:DOJSubpoenaMember 2018-10-01 2019-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ReagentRentalArrangementsMember vivo:LeaseElementsMember us-gaap:SalesRevenueNetMember 2018-10-01 2019-09-30 0000794172 srt:MinimumMember 2018-10-01 2019-09-30 0000794172 srt:MaximumMember 2018-10-01 2019-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2020-09-30 0000794172 vivo:KitsAndReagentsMember 2020-09-30 0000794172 vivo:InstrumentsMember 2020-09-30 0000794172 us-gaap:DomesticCountryMember 2020-09-30 0000794172 us-gaap:ForeignCountryMember 2020-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2020-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2020-09-30 0000794172 vivo:ConsolidationEliminationMember 2020-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2020-09-30 0000794172 us-gaap:CommitmentsMember 2020-09-30 0000794172 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommitmentsMember 2020-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommitmentsMember 2020-09-30 0000794172 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommitmentsMember 2020-09-30 0000794172 us-gaap:InterestRateSwapMember 2020-09-30 0000794172 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2020-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2020-09-30 0000794172 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2020-09-30 0000794172 country:IT 2020-09-30 0000794172 country:CA 2020-09-30 0000794172 country:DE 2020-09-30 0000794172 country:GB 2020-09-30 0000794172 country:IL 2020-09-30 0000794172 us-gaap:MoneyMarketFundsMember 2020-09-30 0000794172 us-gaap:CashMember 2020-09-30 0000794172 vivo:ManufacturingTechnologiesCoreProductsAndCellLinesMember 2020-09-30 0000794172 vivo:TradeNamesLicensesAndPatentsMember 2020-09-30 0000794172 vivo:CustomerListsAndRelationshipsAndSupplyAgreementsMember 2020-09-30 0000794172 us-gaap:NoncompeteAgreementsMember 2020-09-30 0000794172 vivo:FormerChiefExecutiveOfficerMember 2020-09-30 0000794172 vivo:PotentialFutureSeveranceIndemnityMember 2020-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2021-09-30 0000794172 vivo:KitsAndReagentsMember 2021-09-30 0000794172 vivo:InstrumentsMember 2021-09-30 0000794172 us-gaap:DomesticCountryMember 2021-09-30 0000794172 us-gaap:ForeignCountryMember 2021-09-30 0000794172 vivo:StockIncentivePlanTwentyTwentyOneMember 2021-09-30 0000794172 vivo:StockIncentivePlanMember 2021-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2021-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2021-09-30 0000794172 vivo:ConsolidationEliminationMember 2021-09-30 0000794172 us-gaap:StateAndLocalJurisdictionMember 2021-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2021-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2021-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2021-09-30 0000794172 us-gaap:CommitmentsMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommitmentsMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommitmentsMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommitmentsMember 2021-09-30 0000794172 us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2021-09-30 0000794172 country:IT 2021-09-30 0000794172 country:CA 2021-09-30 0000794172 country:DE 2021-09-30 0000794172 country:GB 2021-09-30 0000794172 country:IL 2021-09-30 0000794172 srt:MaximumMember 2021-09-30 0000794172 srt:MinimumMember 2021-09-30 0000794172 srt:MinimumMember vivo:LongTermGovernmentGrantObligationsMember 2021-09-30 0000794172 srt:MaximumMember vivo:LongTermGovernmentGrantObligationsMember 2021-09-30 0000794172 us-gaap:MoneyMarketFundsMember 2021-09-30 0000794172 us-gaap:CashMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:InterestRateSwapMember 2021-09-30 0000794172 vivo:ProductDevelopmentMilestonesAndFinancialPerformanceTargetsMember vivo:GenepocIncMember srt:MaximumMember 2021-09-30 0000794172 vivo:GenepocIncMember srt:MaximumMember vivo:ProductDevelopmentMilestonesAndFinancialPerformanceTargetsMember vivo:OnAcquisitionDateMember 2021-09-30 0000794172 vivo:GenepocIncMember srt:MaximumMember vivo:ProductDevelopmentMilestonesMember 2021-09-30 0000794172 vivo:GenepocIncMember srt:MaximumMember vivo:ProductDevelopmentMilestonesMember vivo:OnAcquisitionDateMember 2021-09-30 0000794172 srt:MaximumMember vivo:GenepocIncMember vivo:FinancialPerformanceTargetsMember 2021-09-30 0000794172 vivo:NationalInstituteOfHealthMember vivo:ReimbursementOfResearchAndDevelopmentExpenditureAccruedMember 2021-09-30 0000794172 vivo:FormerChiefExecutiveOfficerMember 2021-09-30 0000794172 vivo:PotentialFutureSeveranceIndemnityMember 2021-09-30 0000794172 vivo:GenepocIncMember 2019-06-03 0000794172 vivo:GenepocIncMember 2021-08-01 2021-08-31 0000794172 vivo:BreathtekmemberMember 2021-07-01 2021-07-31 0000794172 vivo:BreathtekmemberMember us-gaap:CustomerRelationshipsMember 2021-07-01 2021-07-31 0000794172 vivo:BreathtekmemberMember 2021-07-31 0000794172 vivo:BreathtekmemberMember us-gaap:CustomerRelationshipsMember 2021-07-31 0000794172 vivo:ExalenzMember 2020-04-30 0000794172 us-gaap:CustomerRelationshipsMember vivo:ExalenzMember 2020-04-30 0000794172 us-gaap:TechnologyBasedIntangibleAssetsMember vivo:ExalenzMember 2020-04-30 0000794172 us-gaap:TradeNamesMember vivo:ExalenzMember 2020-04-30 0000794172 us-gaap:NoncompeteAgreementsMember vivo:ExalenzMember 2020-04-30 0000794172 vivo:ManufacturingTechnologiesCoreProductsAndCellLinesMember 2021-10-31 0000794172 vivo:TradeNamesLicensesAndPatentsMember 2021-10-31 0000794172 vivo:CustomerListsAndRelationshipsAndSupplyAgreementsMember 2021-10-31 0000794172 us-gaap:NoncompeteAgreementsMember 2021-10-31 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2019-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2019-09-30 0000794172 vivo:ConsolidationEliminationMember 2019-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember us-gaap:SubsequentEventMember 2021-10-25 0000794172 us-gaap:NoncompeteAgreementsMember vivo:ExalenzMember 2020-04-30 2020-04-30 0000794172 us-gaap:TradeNamesMember vivo:ExalenzMember 2020-04-30 2020-04-30 0000794172 us-gaap:TechnologyBasedIntangibleAssetsMember vivo:ExalenzMember 2020-04-30 2020-04-30 0000794172 us-gaap:CustomerRelationshipsMember vivo:ExalenzMember 2020-04-30 2020-04-30 0000794172 vivo:ExalenzMember 2020-04-30 2020-04-30 0000794172 us-gaap:SubsequentEventMember us-gaap:RevolvingCreditFacilityMember 2021-10-25 2021-10-25 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2018-10-01 2021-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2019-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2019-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2019-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2020-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2020-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2020-09-30 0000794172 us-gaap:RetainedEarningsMember 2020-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2020-09-30 0000794172 us-gaap:CommonStockMember 2020-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2021-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2021-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2021-09-30 0000794172 us-gaap:RetainedEarningsMember 2021-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2021-09-30 0000794172 us-gaap:CommonStockMember 2021-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2018-09-30 0000794172 us-gaap:RetainedEarningsMember 2018-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2018-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2018-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2018-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2018-09-30 0000794172 us-gaap:CommonStockMember 2018-09-30 0000794172 us-gaap:RetainedEarningsMember 2019-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2019-09-30 0000794172 us-gaap:CommonStockMember 2019-09-30 iso4217:USD xbrli:pure xbrli:shares utr:Year utr:Month iso4217:ILS iso4217:USD xbrli:shares vivo:Stock-Plan +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM +10-K +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2021 . +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM +TO +Commission File +No. 0-14902 +MERIDIAN BIOSCIENCE, INC. +3471 River Hills Drive +Cincinnati , Ohio 45244 +IRS Employer ID +No. 31-0888197 +State of Incorporation: Ohio +Phone: ( 513 ) +271-3700 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Trading Symbol +Name of each exchange on which registered +Common Shares , No Par Value +VIVO +The NASDAQ Stock Market LLC +(NASDAQ Global Select Market) +Securities registered pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ☒ NO ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES ☐ NO ☒ +Table of Contents +Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ☒ NO ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation +S-T +(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES ☒ NO ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a +non-accelerated +filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule +12b-2 +of the Exchange Act. +Large accelerated filer +☒ +Accelerated filer +☐ +Non-accelerated filer +☐ +Smaller reporting company +☐ +Emerging growth company +☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule +12b-2). YES ☐ NO ☒ +The aggregate market value of Common Shares held by +non-affiliates +as of March 31, 2021 was $ 1,132,216,391 based on a closing sale price of $26.25 per share on March 31, 2021. As of October 31, 2021, 43,364,448 shares of Common Stock, no par value, were issued and outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Proxy Statement for the 2022 Annual Meeting of Shareholders, which will be filed within one hundred and twenty days of the fiscal year ended September 30, 2021 (2022 Proxy Statement), are incorporated by reference into Part III of this report to the extent described herein. +Table of Contents +MERIDIAN BIOSCIENCE, INC. +INDEX TO ANNUAL REPORT +ON FORM +10-K +Page +Part I +Item 1 +Business +5 +Item 1A +Risk Factors +11 +Item 1B +Unresolved Staff Comments +24 +Item 2 +Properties +24 +Item 3 +Legal Proceedings +24 +Item 4 +Mine Safety Disclosures +25 +Part II +Item 5 +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +25 +Item 6 +Intentionally Omitted +26 +Item 7 +Management’s Discussion and Analysis of Financial Condition and Results of Operations +26 +Item 7A +Quantitative and Qualitative Disclosures about Market Risk +37 +Item 8 +Financial Statements and Supplementary Data +38 +Item 9 +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +74 +Item 9A +Controls and Procedures +74 +Item 9B +Other Information +75 +Part III +Item 10 +Directors, Executive Officers and Corporate Governance +75 +Item 11 +Executive Compensation +75 +Item 12 +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +76 +Item 13 +Certain Relationships and Related Transactions, and Director Independence +76 +Item 14 +Principal Accountant Fees and Services +76 +Item 15 +Exhibits and Financial Statement Schedules +76 +Item 16 +Form 10-K Summary +78 +NOTE ABOUT FORWARD-LOOKING STATEMENTS +This report includes estimates, projections, statements relating to our business plans, objectives, and expected operating results that are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements may appear throughout this report, including the following sections: “Business” (Part I, Item 1 of this Form +10-K), +“Risk Factors” (Part I, Item 1A of this Form +10-K), +and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Part II, Item 7 of this Form +10-K). +These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “future,” “opportunity,” “plan,” “may,” “should,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties that may cause actual results to differ materially. We describe risks and uncertainties that could cause actual results and events to differ materially in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” (Part II, Item 7A of this Form +10-K) +and elsewhere in this Form +10-K. +Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date they are made. We undertake no obligation to update or revise publicly any forward-looking statements, whether because of new information, future events, the novel coronavirus +(“COVID-19”) +pandemic, or otherwise. +Unless the context requires otherwise, references in this Annual Report on +Form 10-K +(“Form +10-K”) +to “Meridian,” “we,” “us,” “our,” “Company,” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +Table of Contents +In the discussion that follows, all dollar amounts and share amounts are in thousands (both tables and text), except per share data. +This Form +10-K +refers to trademarks such as Alethia +® +, BreathID +® +, BreathTek +® +, Curian +® +, HpSA +® +, Immuno +Card +® +, Immuno +Card +STAT! +® +, LeadCare +® +, MyTaq +™ +, PREMIER +® +, revogene +® +and SensiFAST +™ +, which are protected under applicable intellectual property laws and are our property. Solely for convenience, our trademarks and tradenames referred to in this Form +10-K +may appear without the +® +or +™ +symbols, but such references are not intended to indicate in any way that we will not assert, to the fullest extent under applicable law, our rights to these trademarks and tradenames. Our molecular diagnostic test platform formerly known under the tradenames +illumi +gene +and +illumi +pro +, has been rebranded under the tradename Alethia. References to Alethia throughout this Form +10-K +refer to our molecular diagnostic tests and instrumentation formerly marketed and sold under the +illumi +gene +and +illumi +pro +brands. Such references are not intended to indicate, in any way, that we will not assert, to the fullest extent permitted by law, our rights to our trademarks. +WEBSITE AND SOCIAL MEDIA DISCLOSURE +We use our website ( +www.meridianbioscience.com +) and our corporate Facebook, Instagram, LinkedIn, Twitter, Vimeo and YouTube accounts as channels of distribution of company information. The information we post through these channels may be deemed material. Accordingly, investors should monitor these channels, in addition to following our press releases, Securities and Exchange Commission (“SEC”) filings and public conference calls and webcasts. The contents of our website and social media channels are not, however, a part of this report. +MARKET AND INDUSTRY INFORMATION +Market data used throughout this Form +10-K +is based on management’s knowledge of the industry and good faith estimates of management. All of management’s estimates presented herein are based on industry sources, including analyst reports and management’s knowledge. We also relied, to the extent available, upon management’s review of independent industry surveys and publications prepared by a number of sources and other publicly available information. We are responsible for all of the disclosures in this Form +10-K +and while we believe that each of the publications, studies and surveys used throughout this Form +10-K +are prepared by reputable sources, we have not independently verified market and industry data from third-party sources. +All of the market data used in this Form +10-K +involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. While we believe the estimated market position, market opportunity and market size information included in this Form +10-K +is generally reliable, such information, which in part is derived from management’s estimates and beliefs, is inherently uncertain and imprecise and has not been verified by any independent source. Projections, assumptions and estimates of our future performance and the future performance of the industry in which we operate are subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Item 1A. Risk Factors” of Part I of this Form +10-K +and elsewhere in this Form +10-K. +These and other factors could cause results to differ materially from those expressed in our estimates and beliefs and in the estimates prepared by independent parties. +- 4 - +Table of Contents +PART I. +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in: (i) the development, manufacture, sale and distribution of diagnostic testing systems and kits, primarily for certain gastrointestinal and respiratory infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, and bioresearch reagents used by other diagnostic test manufacturers and researchers in immunological and molecular tests for human, animal, plant and environmental applications. +Our website is +www.meridianbioscience.com +. We make available our Annual Reports on Form +10-K, +Quarterly Reports on Form +10-Q, +Current Reports on Form +8-K, +Proxy Statements and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the SEC. The SEC maintains an internet site containing these filings and other information regarding Meridian at +www.sec.gov +. The information on our website is not and should not be considered part of this Form +10-K. +Reportable Segments +Our reportable segments are Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. We describe these reportable segments in this “Business” section and in other locations in this report: +Type of Segment Information +Location within Form +10-K +Physical locations and activities +Item 2. “Properties” +Revenue by geographic region +Item 7. “Management’s Discussion and Analysis of Financial Condition & Results of Operations” (hereafter “MD&A”) +Financial information +Item 8. “Note 15 of Consolidated Financial Statements” +Diagnostics Segment +Products and Markets +Prior to the onset of the +COVID-19 +pandemic early in 2020, our largest source of net revenues was clinical diagnostic products, historically representing approximately +two-thirds +of our consolidated net revenues. However, primarily due to the effects of the +COVID-19 +pandemic, our Diagnostics segment provided 40% of consolidated net revenues for fiscal 2021, following 48% of consolidated net revenues for fiscal 2020. In 2022, we expect our Diagnostics segment to contribute approximately 50% of our consolidated net revenues. +Our clinical diagnostic products provide accuracy, simplicity and speed; enable early diagnosis and treatment of acute medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that: (i) are conditions where rapid diagnosis impacts patient outcomes; (ii) have opportunistic demographic and disease profiles; (iii) are underserved by current diagnostic products; and/or (iv) have difficult sample handling requirements (e.g., stool). This approach has allowed us to establish meaningful market share in our target disease states, gastrointestinal and respiratory illnesses, and tests for elevated lead levels in blood. +Our product portfolio includes just under 200 diagnostic tests and transport media, and is marketed to acute care hospitals, reference laboratories, outpatient clinics and physician office laboratories in over 70 countries around the world. Our testing platforms include: Real-time PCR Amplification (Revogene brand); Isothermal DNA Amplification (Alethia brand); Lateral Flow Immunoassay using fluorescent chemistry (Curian brand); Rapid Immunoassay (Immuno +Card +and Immuno +Card +STAT! brands); +Enzyme-linked +Immunoassay (PREMIER brand); Anodic Stripping Voltammetry (LeadCare brands); and urea breath testing for +H. pylori +(BreathID and BreathTek brands). +- 5 - +Table of Contents +Our diagnostic assay research and development programs are focused on menu expansion for our Curian and Revogene instrument platforms, with disease targets in the gastrointestinal and respiratory areas, as well as next generation blood-chemistry testing. Currently pending clearance at the U.S. Food and Drug Administration (“FDA”) is a 510(k) application for the Curian Campylobacter assay. Our current new product development pipeline includes gastrointestinal and respiratory multi-plex assays on our Revogene instrument platform, and EHEC Shiga Toxin and +C. difficile +combo common antigen and Toxins A and B on our Curian instrument platform. In addition, we have other assays on both platforms moving through our upstream marketing assessment processes that are expected to add to the development pipeline. For our BreathID platform, we are actively looking at the feasibility of combining Urea and Citrica into a single sachet or pouch, which would meaningfully improve our cost of manufacturing BreathID assays. We are also pursuing opportunities to complement our internal research and development programs by securing rights to finished diagnostics tests that we can immediately commercialize. +The April 2020 acquisition of Exalenz Bioscience Ltd. (“Exalenz”) and the BreathID system, along with the July 2021 acquisition of the BreathTek business, strengthened our position in +H. pylori +testing, as these products provide an alternative +non-invasive +testing approach versus stool antigen testing. +Market Trends +Despite the effects of the +COVID-19 +pandemic and the intense focus on +SARS-CoV-2 +testing, we believe the global market for infectious disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. There is a continuing shift from conventional testing to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The growing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. Integrated Delivery Networks (“IDNs”) in our U.S. market have the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with IDNs and health care systems that are transitioning from +fee-for-service +compensation models to value-based reimbursement. +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing organizations and IDNs, consolidation among reference laboratories, hospital laboratories being operated by large reference laboratories, and acquisition of physician practices by hospitals, health systems and +for-profit +specialty health care companies. +Cost containment pressures have also affected health care systems outside the U.S., particularly in Europe, where the health care systems are generally +government-run. +The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing and Distribution +Our Diagnostics segment relies on direct sales personnel and independent distribution networks. We have a direct sales force in four countries, covering the United States (“U.S.”) and certain major markets in the EMEA region (i.e., in Europe, the Middle East and Africa). We also use independent distributors either in a complementary manner with our direct sales force (e.g., the U.S.) or solely to supply our products to +end-users. +We have two independent distribution customers and a reference laboratory customer that together comprised 33% of Diagnostics segment net revenues in fiscal 2021, with each contributing 10% or greater of the Diagnostics segment’s net revenues. +Competition +Our major competitors in molecular diagnostics are Cepheid (a Danaher business) and Becton Dickinson, both of which have systems with multiple-assay menus. We also face competition in molecular diagnostics, but to a lesser degree, from companies such as Abbott (former Alere business) and Quidel. +- 6 - +Table of Contents +Our major competitors in rapid immunoassay diagnostics are primarily Abbott (former Alere business) and Quidel. In recent years, companies such as bioMerieux have captured market share in our gastrointestinal category via its BioFire multi-plex panel tests. However, since their introduction to the market, payors have raised concerns over reimbursement levels relative to clinical utility, particularly for panels with 12 or more targets. +For blood lead testing, we believe we have the only +FDA-cleared, +CLIA-waived +point-of-care +test available commercially. Other blood lead testing systems in use, marketed by our competitors, include Graphite Furnace Atomic Absorption Spectroscopy, which requires a highly skilled technician and larger laboratory space to operate, in addition to not being portable or suitable for +point-of-care +use. See product recall discussion included in “Lead Testing Matters” beginning on page 29 within MD&A. +Research and Development +Our Diagnostics segment’s research and development personnel are organized into three +pre-clinical +teams: immunoassay, +PCR-based +molecular and blood-chemistry. We have a separate team responsible for execution of clinical trials across all three +pre-clinical +programs. Our research and development activities are focused on new product and new technology development, new applications for our existing technologies, and improvements to existing products, including assay-menu expansion. Research and development efforts may occur +in-house +or with collaborative partners. We believe that new product development is a key source for sustaining revenue growth. The products within our Revogene and Alethia molecular platforms, +H. pylori +product family and blood lead testing family were developed +in-house. +Manufacturing +Our diagnostics products are manufactured at four principal sites in Billerica, Massachusetts (blood-chemistry); Cincinnati, Ohio (immunoassays and molecular tests); Modi’in, Israel, (urea breath tests for +H. pylori +); and Quebec City, Quebec, Canada (molecular tests). Our immunoassay and molecular assay products require the production of highly specialized reagents, primers and enzymes, and our BreathID and BreathTek products require the production of urea in pharmaceutical-grade form. We produce the vast majority of our own immunoassay requirements. Reagents, primers and enzymes for our Revogene molecular assay products, primers for our Alethia molecular assay products, and urea for our BreathID and BreathTek systems are purchased from outside vendors. Our blood lead testing products require the production of electrical chemical sensors, which we manufacture using critical raw materials purchased from outside vendors. +Intellectual Property, Patents and Licenses +We own or license U.S. and foreign patents, most of which are for select products manufactured by our Diagnostics segment. These patents are used in our manufacturing processes for select products (e.g., method patents) or may relate to the design of the test device technology format (e.g., design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully replicate our production and manufacturing technologies and processes. Our employees are required to sign confidentiality and +non-disclosure +agreements designed to protect our proprietary products. +The patents applicable to our Alethia products, which represented 4%, 7% and 12% of consolidated net revenues for fiscal 2021, 2020 and 2019, respectively, have been and continue to be licensed from a third party, Eiken Chemical Co., Ltd., under a +non-exclusive +license agreement, with the last remaining U.S. patent expiring in 2022. +The patents for the Revogene platform and related products acquired as part of the GenePOC business are either wholly owned or licensed from two third parties, Laval University and The Regents of California, under an exclusive license agreement. These patents are issued in the U.S., European Union (“EU”) and other countries. The term of our exclusive license agreement and the related patents currently runs through June 15, 2034, after which we will be free to practice the patents without any restriction or royalty obligation. In September 2021, the U.S. Patent and Trademark Office granted to Meridian Bioscience Canada Inc. (a wholly owned subsidiary) and Laval University a patent for our current Revogene test device and its microfluidic use in our Revogene instrument. +The patents for the BreathID system and related urea breath test for +H. pylori +are either wholly owned or licensed from a third party, Oridion Medical 1987 Ltd., under an exclusive, royalty free, license agreement. The licensed and wholly owned patents are issued in the U.S., EU, Israel, Japan, Australia and China. The wholly owned patents have varying expiration dates, with the last being in 2033. +- 7 - +Table of Contents +The patents for our stool antigen +H. pylori +products, owned by us and which represented approximately 7%, 9% and 17% of consolidated net revenues for fiscal 2021, 2020 and 2019, respectively, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. As a result, competition with respect to our stool antigen +H. pylori +products has increased, adversely impacting our selling prices for these products, and/or our ability to retain business at prices acceptable to us. To mitigate certain of the pricing and volume pressures we face within the gastrointestinal product category, we have: (i) operated under a strategic collaboration agreement with DiaSorin to sell +H. pylori +tests; (ii) adjusted selling prices to secure volume; and (iii) upon FDA clearance in March 2020, launched Curian HpSA, our first assay on the Curian platform, which we expect will help protect our existing customer base using lateral flow tests. We also expect the BreathID and BreathTek products to mitigate competitive pressures, as these products provide an alternative +non-invasive +option to stool antigen testing. We are unable to provide assurances that we will be successful with any strategy or that any strategy will prevent an adverse effect on our future results of operations and liquidity, including net revenues and gross profit. +Government Regulation +Our diagnostic products are regulated by the FDA as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (“FDCA”). Under the FDCA, medical devices are classified into one of three classes (i.e., Class I, II or III). Class I and II devices are not expressly approved by the FDA, but, instead, are “cleared” for marketing. Class III devices generally must receive +“pre-market +approval” (“PMA”) from the FDA as to safety and effectiveness. Our diagnostics manufacturing facilities are subject to periodic inspection by the FDA. See page 29 within MD&A for discussion regarding the FDA’s inspection of our Billerica facility. +Each of the diagnostic products currently marketed by Meridian in the U.S. has been cleared, approved or authorized for use by the FDA or are exempt from such requirements. The majority of such products have been cleared by the FDA pursuant to its 510(k) clearance process, with our BreathTek product having been approved under the FDA’s PMA process. In the case of our Revogene +SARS-CoV-2 +test, it has not been FDA cleared or approved but rather has been authorized by the FDA for emergency use under its Emergency Use Authorization (“EUA”) process. We believe that most products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all Class II devices, will be eligible for 510(k) clearance; however, we can make no assurances in this regard. Our urea breath test for +H. pylori +on the BreathID system was cleared as a Class I medical device since the urea drug component was approved by the FDA separately via the New Drug Application process. Our urea breath test for +H. pylori +on the BreathTek system was approved by the FDA via the PMA process in 2012. Our +SARS-CoV-2 +test on the Revogene platform was submitted to the FDA under its EUA program on June 25, 2021, with EUA being granted on November 9, 2021. +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, which is similar to that of the FDA. Our Diagnostics segment facilities are certified to ISO 13485. +Following a five-year transition period, sales of our diagnostic products in the EU will be subject to new regulations under the In Vitro Diagnostics Regulation of 2017 (“IVDR”) beginning in May 2022. IVDR replaces the previous IVD Regulation (98/79/EC). In October 2021, the European Commission submitted a proposal to the European Parliament that would move back the May 2022 implementation date for diagnostic tests that are currently CE Marked to dates ranging from May 2025 to May 2028, depending on the risk classification of the diagnostic test. We have completed an assessment of needed remediation activities to comply with IVDR and also determined that several products will not be sellable under IVDR. The net revenues associated with these products are not expected to be material. New diagnostic products launched after May 2022 are required to comply with IVDR. +Life Science Segment +Products and Markets +Our Life Science segment develops, manufactures, sells and distributes bulk antigens, antibodies, immunoassay blocking reagents, specialized PCR master mixes, isothermal reagents, enzymes, nucleotides, and bioresearch reagents used predominantly by in vitro device (“IVD”) manufacturing companies, and to a lesser degree, by researchers and +non-human +clinical customers such as veterinary, food and environmental. The +COVID-19 +pandemic has provided the opportunity for our Life Science segment to showcase the breadth of its reagent products across not only +SARS-CoV-2 +testing platforms (molecular, rapid antigen and serology), but also RNA and DNA based molecular tests for nearly any infectious disease. For fiscal 2021, approximately 87% of Life Science segment net revenues were generated from the industrial market, defined as IVD manufacturers, and reagents for use in +SARS-CoV-2 +tests contributed approximately $111,900 of net revenues, following $71,500 in fiscal 2020. We engage direct sales teams in the U.S., the United Kingdom (“U.K.”), France, Germany, China and Australia. During fiscal 2021, 22% of net revenues for this segment were from three IVD manufacturing customers. +- 8 - +Table of Contents +Our Life Science segment products are marketed to IVD manufacturing customers as a source of raw materials for their human clinical diagnostics tests, or as an outsourced step in their manufacturing processes. Selectively, we seek and maintain multi-year supply arrangements to provide stability in volumes and pricing. Independent distributors market our molecular biology products to academic/research customers. These products are used in detecting DNA and RNA in human, animal, plant and environmental applications. +Market Trends +Major IVD manufacturing customers often have global footprints, where we are supplying reagents to specific manufacturing sites around the world. IVD manufacturers in specific countries of the Asia-Pacific region (e.g., China) are increasing their efforts in the development and manufacturing of infectious disease tests. We intend to use the breadth of our product portfolio, particularly molecular reagents, to continue to increase the penetration of our products in IVD manufacturing customers’ tests, regardless of customer class (large multi-national companies or regional companies). +Competition +The market for bulk biomedical reagents is highly competitive with respect to product quality, price, customer service and reputation. Our competitors, such as Thermo Fisher, often have greater financial, research and development, sales and marketing, and manufacturing resources. Customers also may choose to manufacture their biomedical reagents +in-house +rather than purchase from us. +Research and Development +Our research and development activities for the Life Science segment focus on molecular reagents for use in PCR and isothermal chemistries in detecting both DNA and RNA. Our new product development programs are progressing through sample-specific (e.g., blood, saliva, urine, stool, and plant) mixes in both +air-dryable +and lyophilization-ready forms, and isothermal reagents in both +air-dryable +and lyophilization-ready forms. We also have enzyme development programs that meet the EU Registration, Evaluation, Authorization, and Restriction of Chemicals regulation. See “Operating Expenses” section on page 33 within MD&A. +Manufacturing and Government Regulation +Our Life Science segment facilities are ISO 13485 certified, and where appropriate, our Life Science segment facilities comply with Regulation EC 1069. +International Markets +International markets are an important source of net revenues and future growth opportunities for both of our reportable segments. For both reportable segments combined, net revenues from customers located outside of the U.S. and its territories approximated $173,000 or 55% of consolidated 2021 net revenues, $122,000 or 48% of consolidated 2020 net revenues, and $74,000 or 37% of consolidated 2019 net revenues. Since the outbreak of the +COVID-19 +pandemic in fiscal 2020 and throughout fiscal 2021, a significantly higher percentage of our Life Science segment’s net revenues have been generated from international markets, and we expect to continue to look to key European and Asian markets as a source of revenue growth. For the Life Science segment, we also continue to focus resources on IVD manufacturing customers in China, India, Japan and Korea. To date, we have not experienced any adverse effects from the trade tensions between the U.S. and China, but we cannot be sure that we will not experience any adverse effects in the future. +Fluctuations in foreign currency exchange rates in fiscal 2021 compared to fiscal 2020 had an approximate $9,200 favorable impact on consolidated 2021 net revenues; $1,300 within the Diagnostics segment and $7,900 within the Life Science segment. This compares to +year-to-year +currency exchange rates having an approximate $1,250 unfavorable impact on consolidated net revenues in 2020; $150 within the Diagnostics segment and $1,100 within the Life Science segment. In fiscal 2019, the unfavorable effect on net revenues totaled $2,200; $1,150 within the Diagnostics segment and $1,050 within the Life Science segment. +- 9 - +Table of Contents +Environmental +We are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. +Human Capital +As of September 30, 2021, our Diagnostics segment had approximately 560 employees in ten countries, our Life Science segment had approximately 200 employees in seven countries, and Corporate had five employees, all in the U.S. Approximately 55% of our employees are women. In addition, of our U.S. based employees, which represents approximately 60% of our total worldwide workforce, approximately 25% are ethnically diverse. +Below is additional demographic information about our current employee base as of September 30, 2021. +Meridian Employees +2021 +Salaried workforce +543 +Managers and above +159 +Part-time employees +27 +Average age +43 +Average length of service in years +7 +Employee turnover rate (voluntary) +19 +% +Fiscal 2021 net revenues per employee (in thousands) +$ +415 +Equal Employment Opportunity Table (by number of employees) +U.S. Employee Diversity as of September 30, 2021 +Job category +Gender +White +Black/African +American +Hispanic/Latino +Asian +American +Indian/Alaskan +Native +Two +or +more +races +Total +Executive/senior level officials and managers +Male +12 +— +— +— +— +— +12 +Female +3 +— +1 +— +— +— +4 +First/mid-level +officials and managers +Male +41 +4 +2 +3 +— +— +50 +Female +36 +4 +— +4 +— +1 +45 +Professionals +Male +60 +4 +4 +5 +— +1 +74 +Female +71 +9 +5 +9 +— +2 +96 +All other +Male +59 +11 +8 +5 +— +1 +84 +Female +83 +18 +7 +8 +— +2 +118 +Total +Male +172 +19 +14 +13 +— +2 +220 +Female +193 +31 +13 +21 +— +5 +263 +We believe that developing a diverse, equitable and inclusive culture is critical to continuing to attract and retain the top talent necessary to deliver on our growth strategy. As such, we continue to invest in the creation of a work environment where our employees can feel inspired to deliver their workplace best every day. We continue to expand our Human Resources Information System (“HRIS”) and other systems to track key human capital metrics, including workforce demographics, diversity, turnover, engagement, and training data. +Diversity, Equity and Inclusion +In 2020, we initiated the “One Meridian Inclusion Diversity and Equity Team,” which is comprised of a group of employees around the world and led by Dr. Lourdes Weltzien, Executive Vice President, Life Science. This team has developed a mission statement and promotes awareness so we can encourage and support an environment in which all employees feel included and empowered to achieve their best. +- 10 - +Table of Contents +Compensation and Benefits +We strive to provide pay, benefits, and services that are competitive to market and create incentives to attract and retain employees globally. Our compensation packages include market-competitive pay, cash bonuses, health care and retirement benefits, paid time off, and family leave, among others, depending upon locale. We are focused on pay equity globally and are striving to close the gap in pay among similar roles and responsibilities in certain locations within our organization, after accounting for legitimate business factors that can explain differences, such as performance, time at grade level, and tenure. We intend to conduct market surveys every two years to assess market compensation levels from a total compensation perspective. We also continue to advance transparency in our pay and representation data by complying with all applicable statutory filing requirements. +Communication and Engagement +We strongly believe that Meridian’s success depends on employees understanding how their work contributes to the Company’s overall strategy. To this end, we utilize a variety of channels to facilitate open and direct communication, including: (i) One Meridian Company-wide intranet; (ii) quarterly CEO update videos; (iii) open forums or town hall meetings with executives; (iv) regular ongoing update communications; and (v) employee engagement surveys. +Health, Wellness and Safety +We are committed to the safety of our employees and communities, from operations to product development to supplier partnerships. Our ultimate goal is to achieve zero serious injuries through continued investment in, and focus on, our core safety programs and injury-reduction initiatives. We provide access to a variety of innovative, flexible, and convenient health and wellness tools. +ITEM 1A. +RISK FACTORS +In addition to the other information set forth in this report, you should carefully consider the following factors, which could materially affect our business, financial condition, cash flows or future results. Any one of these factors could cause our actual results to vary materially from recent results or from anticipated future results. The risks described below are not the only risks facing our company. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may materially adversely affect our business, financial condition and/or operating results. +Risk Factors Summary +Risks Related to Our Strategy +• +Our financial condition, results of operations and cash flows could be adversely affected by the ongoing and evolving +COVID-19 +pandemic. +• +Net revenues for our Diagnostics segment may be impacted by our reliance upon large customers in North America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +• +Net revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +• +Intense competition could adversely affect our profitability and operating results. +• +We expect to continue to face increased competition resulting from the expiration of our +H. pylori +patents. +Risks Related to our Intellectual Property +• +We may be unable to protect or obtain adequate patent protection for intellectual property that we utilize or intend to utilize. +• +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Risks Related to our Operations +• +We may be unable to develop new products or acquire products on favorable terms. +- 11 - +Table of Contents +• +We may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions we make. +• +The effective tax rate of the Company may be negatively impacted by changes in the mix of earnings as well as future changes to tax laws in global jurisdictions in which we operate. +• +Significant interruptions in production at our principal manufacturing facilities and/or third-party manufacturing facilities could adversely affect our business and operating results. +• +We depend on sole-source suppliers for certain critical raw materials, components and finished products. A supply interruption could adversely affect our business. +• +Our ability to meet future customer demand for selected products is dependent upon our ability to successfully manage our manufacturing capacity and supply chains. +• +Increased prices for, poor quality of, or extended inability to source raw materials or services used in our products, and supply chain disruptions, could adversely affect profitability. +Risks Related to Legal, Regulatory and International Matters +• +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +• +If we or our third-party vendors fail to comply with FDA regulations relating to the manufacturing of our products or any component part, we may be subject to fines, injunctions and penalties, and our ability to commercially distribute and sell our products may be negatively impacted. +• +We incur costs and demands upon management as a result of complying with the laws and regulations affecting public companies in the U.S., and failure to comply with these laws could harm our business and the price of our common stock. +• +We could be adversely affected by health care reform legislation. +• +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +• +Global market, political, environmental, and economic conditions, including those related to the financial markets, could have a material adverse effect on our operating results, financial condition, and liquidity. +• +We depend on international net revenues, and our operating results may be adversely impacted by foreign currency, regulatory or other developments affecting international markets. +• +New tariffs and other trade measures could adversely affect our operating results. +• +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and may have to limit or cease sales of our products. +Risks Related to Our Common Stock +• +The market price of our common stock may be volatile and fluctuate significantly, which could result in substantial losses for stockholders and subject us to litigation. +• +Our business could be negatively impacted as a result of shareholder activism, an unsolicited takeover proposal or a proxy contest. +• +The authority of our board to issue preferred stock and the effects of certain provisions of Ohio corporation law may discourage takeover bids. +General Risk Factors +• +One or more cybersecurity incidents may adversely impact our financial condition, results of operations and reputation. +• +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +• +Our bank credit agreement imposes restrictions with respect to our operations, which could adversely impact our business. +Risks Related to Our Strategy +Our financial condition, results of operations and cash flows could be adversely affected by the ongoing and evolving +COVID-19 +pandemic. +Any outbreak of contagious diseases, such as +COVID-19, +or other adverse public health developments, could have material and adverse effects on our business operations. Such adverse effects could include diversion or prioritization of health care resources away from the conduct of diagnostic testing, disruptions of or restrictions on the ability of laboratories to process our tests, and delays with respect to or difficulties in patients accessing our tests, including those resulting from an inability to travel as a result of quarantines or other restrictions resulting from +COVID-19. +As +COVID-19 +continues to affect individuals and businesses around the globe, we may experience disruptions that could severely impact our business, including: +- 12 - +Table of Contents +• +decreased volume of testing and related sales of certain of our Diagnostics segment products as a result of disruptions to health care providers and limitations on the ability of providers to administer tests; +• +disruptions or restrictions on the ability of the Company’s, our collaborators’, or our suppliers’ personnel to travel, and temporary closures of our facilities, or the facilities of our collaborators or suppliers; +• +limitations on employee resources that would otherwise be focused on the development of our products, the processing of our diagnostic tests, and/or the conduct of our clinical trials, because of illness of employees or their families, or requirements imposed on employees to avoid contact with large groups of people; and +• +delays in necessary interactions with local regulators, ethics committees, and other important agencies and contractors due to limitations in employee resources or forced furlough of government employees. +In addition, the continued spread of +COVID-19 +globally could adversely affect our manufacturing and supply chains. Parts of our direct and indirect supply chains are located overseas, including in China, and may accordingly be subject to disruption. Additionally, our results of operations could be adversely affected to the extent that +COVID-19 +or any other epidemic harms our business or the economy in general either domestically or in any other region in which we do business. The extent to which +COVID-19 +affects our operations will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration of the outbreak, new information that may emerge concerning the severity of +COVID-19, +and the actions to contain +COVID-19 +or treat its impact, among others, which could have an adverse effect on our business, results of operations and financial condition. Over the course of the +COVID-19 +pandemic, we have generally seen a slowing of our assay instrument placements and sales of related test kits, as diagnostic testing sites turned their attention to critical care testing. We are unable to predict when expected sales volume levels for our instruments and related test kits will return. Also, as a result of the +COVID-19 +pandemic, certain clinical trials related to our products which were underway or scheduled to begin have been temporarily placed on hold. Such delays will impact our timing for filing applications for product clearances with the FDA, as well as related timing of FDA clearances of such filings. Additionally, the +COVID-19 +pandemic could slow down our efforts to expand our product portfolio through acquisition opportunities, impacting the speed with which we are able to bring additional products to market. +Net revenues for our Diagnostics segment may be impacted by our reliance upon large customers in North America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +Key Distributors +Our Diagnostics segment’s net revenues from sales through three customers, including two key distributors, were approximately 33%, 32% and 31% of the Diagnostics segment’s total net revenues for 2021, 2020 and 2019, respectively, or approximately 13%, 15% and 21%, respectively, of each year’s consolidated net revenues. The loss of any one of these customers could negatively impact our net revenues and results of operations unless suitable alternatives were timely found or in the case of distributor customers, lost sales to one distributor were absorbed by another distributor. Finding a suitable alternative on satisfactory terms may pose challenges in our industry’s competitive environment. As an alternative, we could expand our efforts to distribute and market our products directly. This alternative, however, would require substantial investment in additional sales, marketing and logistics resources, including hiring additional sales and customer service personnel, which would significantly increase our future selling, general and administrative expenses. +In addition, buying patterns of these customers may fluctuate from quarter to quarter, potentially leading to uneven concentration levels on a quarterly basis. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal and respiratory infectious diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as an influenza outbreak or the +COVID-19 +pandemic. While we believe that the breadth of our Diagnostics segment product lines normally reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in Diagnostics segment net revenues, the +COVID-19 +pandemic has had a significant adverse impact on our Diagnostics segment net revenues since it began in fiscal 2020. Accordingly, we can make no assurance that net revenues will not be negatively impacted period over period by such factors. +- 13 - +Table of Contents +Changing Diagnostic Market Conditions +Changes in the U.S. health care delivery system have resulted in consolidation among reference laboratories, hospital laboratories being operated by large reference laboratories, and the formation of multi-hospital alliances, reducing the number of institutional customers for diagnostic test products. Consolidation in the U.S. health care industry has also led to the creation of group purchasing organizations (“GPOs”) and IDNs that aggregate buying power for hospital groups and put pressure on our selling prices. Due to such consolidation, we may not be able to enter into and/or sustain contractual or other marketing or distribution arrangements on a satisfactory commercial basis with institutional customers, GPOs and/or IDNs, which could adversely affect our results of operations. +Net revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +Our Life Science segment’s net revenues from three diagnostic manufacturing customers were 22%, 30% and 27% of the Life Science segment’s total net revenues for 2021, 2020 and 2019, respectively. Sales to these three diagnostic manufacturing customers comprised 13%, 16% and 9% of consolidated net revenues for 2021, 2020 and 2019, respectively. In addition, in excess of 10% of the Life Science segment’s total net revenues has historically been concentrated among a number of other significant customers. Any significant alteration of buying patterns from these customers resulting from the decline in +COVID-19 +related demand, or otherwise, could adversely affect our period over period net revenues and results of operations. +Intense competition could adversely affect our profitability and operating results. +The markets for our products and services are characterized by substantial competition and rapid change. Hundreds of companies around the world supply diagnostic tests and immunoassay and molecular reagents. These companies range from multinational health care entities, for which diagnostics is one line of business, to small +start-up +companies. Many of our competitors have significantly greater financial, technical, manufacturing and marketing resources than we do. We cannot provide assurance that our products and services will be able to compete successfully with the products and services of our competitors. +We expect to continue to face increased competition resulting from the expiration of our H. pylori patents. +The patents for our stool antigen +H. pylori +products, owned by us, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. As a result, competition with respect to our stool antigen +H. pylori +products, high margin products which represent approximately 7% of our total net revenues has increased, adversely impacting our selling prices for these products, and/or our ability to retain business at prices acceptable to us. To mitigate certain of the pricing and volume pressures we face within the gastrointestinal product category, we have: (i) operated under a strategic collaboration agreement with DiaSorin to sell +H. pylori +tests; (ii) adjusted selling prices to secure volume; and (iii) upon FDA clearance in March 2020, launched Curian HpSA, our first assay on the Curian platform, which we expect will help protect our existing customer base using lateral flow tests. We also expect the BreathID and BreathTek products to mitigate competitive pressures, as these systems provide an alternative +non-invasive +option to stool antigen testing. We are unable to provide assurances that we will be successful with any strategy or that any strategy will prevent an adverse effect on our future results of operations and liquidity, including net revenues and gross profit. +Risks Related to Our Intellectual Property +We may be unable to protect or obtain adequate patent protection for intellectual property that we utilize or intend to utilize. +In developing and manufacturing our products, we employ a variety of proprietary and patented technologies. In addition, we have licensed, and expect to continue to license, various complementary technologies and methods from academic institutions and public and private companies. We cannot provide assurance that the technologies that we own or license provide protection from competitive threats or from challenges to our intellectual property. In addition, we cannot provide assurances that we will be successful in obtaining and retaining licenses, or proprietary or patented technologies, in the future. +- 14 - +Table of Contents +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Litigation over intellectual property rights is prevalent in the life science and diagnostic industries. As the market for diagnostics continues to grow and the number of participants in the market increases, we may increasingly be subject to patent infringement claims. It is possible that a third party may claim infringement against us. If found to infringe, we may attempt to obtain a license to such intellectual property; however, we may be unable to do so on favorable terms, or at all. Additionally, if our products are found to infringe on third-party intellectual property, we may be required to pay damages for past infringement and lose the ability to sell certain products, causing our revenues to decrease. Any substantial loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our future results of operations and liquidity, including net revenues and gross profit. +Risks Related to Our Operations +We may be unable to develop new products or acquire products on favorable terms. +The medical diagnostic and life science industries are characterized by ongoing technological developments and changing customer requirements. As such, our results of operations and continued growth depend, in part, on our ability in a timely manner to develop or acquire rights to, and successfully introduce into the marketplace, enhancements of existing products and services, or new products and services that incorporate technological advances, meet customer requirements, and/or respond to products developed by our competition. We cannot provide any assurance that we will be successful in developing or acquiring such rights to products and services on a timely basis, or that such products and services will adequately address the changing needs of the marketplace, either of which could adversely affect our results of operations. +In addition, we must regularly allocate considerable resources to research and development of new or acquired products, services and technologies, and protecting intellectual property. The research and development process generally takes a significant amount of time from research to product launch. This process is conducted in various stages. During each stage, there is a risk that we will not achieve our goals on a timely basis, or at all, and we may have to abandon a project in which we have invested substantial resources, any of which could adversely affect our results of operations. +We may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions we make. +One of our growth strategies is the acquisition of companies and/or products. Although additional acquisitions of companies and products may enhance the opportunity to increase net earnings over time, such acquisitions could result in greater administrative burdens, increased exposure to the uncertainties inherent in marketing new products, financial risks of additional operating costs, disrupted operations, challenges in employee retention, and increased risk of asset impairments if future net revenues and cash flows are deficient. The principal benefits expected to result from any acquisitions we make will not be achieved fully unless we are able to successfully integrate the operations of the acquired entities with our operations and realize the anticipated synergies, cost savings and growth opportunities from integrating these businesses into our existing businesses. We cannot provide assurance that we will be able to identify and complete additional acquisitions on terms we consider favorable or that, if completed, will be successfully integrated into our operations. Furthermore, we cannot predict the outcome of goodwill impairment testing and the impact of goodwill impairments on the Company’s net earnings and results of operations. +The effective tax rate of the Company may be negatively impacted by changes in the mix of earnings as well as future changes to tax laws in global jurisdictions in which we operate. +We are subject to income taxes in the U.S. and various other global jurisdictions. Our effective tax rate could be adversely affected by changes in the mix of earnings by jurisdiction and the valuation of deferred tax assets and liabilities. Recently, the current U.S. presidential administration committed to tax reform, and if enacted, the impact could be material to our tax provision and value of deferred tax assets and liabilities. We recognize deferred tax assets and liabilities based on the differences between the consolidated financial statement carrying amounts and the tax basis of assets and liabilities. Significant judgment is required in determining our provision for income taxes. We regularly review our deferred tax assets for recoverability and establish a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized. If we are unable to generate sufficient future taxable income, if there is a material change in the actual effective tax rates, or if there is a change to the time period within which the underlying temporary differences become taxable or deductible, we could be required to increase our valuation allowance against our deferred tax assets, which could result in a material increase in our effective tax rate. +- 15 - +Table of Contents +Changes in tax laws or tax rulings could have a material impact on our effective tax rate. Many countries in the EU, as well as several other countries and organizations such as the Organization for Economic Cooperation and Development, are actively considering changes to existing tax laws. Certain proposals could include recommendations that could increase our tax obligations in those countries where we do business. Any changes in the taxation of our activities in such jurisdictions may result in a material increase in our effective tax rate. +Significant interruptions in production at our principal manufacturing facilities and/or third-party manufacturing facilities would adversely affect our business and operating results. +Products and services manufactured at facilities we own or lease comprised a majority of our net revenues. Our global supply of these products and services is dependent on the uninterrupted and efficient operation of these facilities. In addition, we currently rely on a small number of third-party manufacturers to produce certain of our diagnostic products and product components. The operations of our facilities or these third-party manufacturing facilities could be adversely affected by power failures, or natural or other disasters such as earthquakes, floods, tornadoes or terrorist threats. Although we carry insurance to protect against certain business interruptions at our facilities, there can be no assurance that such coverage will be adequate or that such coverage will continue to remain available on acceptable terms, if at all. Any significant interruption in the Company’s or a third-party supplier’s manufacturing capabilities, including interruptions that have resulted from product recall activities like those currently being experienced in our Billerica facility (see “Lead Testing Matters” beginning on page 29 within MD&A) could materially and adversely affect our results of operations. +We depend on sole-source suppliers for certain critical raw materials, components and finished products. A supply interruption could adversely affect our business. +Raw Materials and Components +Our diagnostic products are made from a wide variety of raw materials that are biological or chemical in nature, and that generally are available from multiple sources of supply. We sole-source certain raw materials and components, which makes it time consuming and costly to switch raw materials and components in +FDA-cleared +products. If certain suppliers fail to supply required raw materials or components, we will need to secure other sources which may require us to conduct additional development and testing and obtain regulatory approval. These activities require significant time and resources, and there is no assurance that new sources will be secured or regulatory approvals, if necessary, will be obtained. +We utilize third-party manufacturers for certain of our instrumentation. One third party manufactures our proprietary Alethia Incubator/Reader (instrument), a component of our Alethia molecular system, and an additional third party manufactures our Curian instrument. These instruments are manufactured exclusively for Meridian according to our specifications. While other manufacturers for these types of instruments are available, we source each instrument solely from one manufacturer to limit the costs involved in clearing the system for marketing in the U.S. If these third-party manufacturers fail to supply us with instruments, we will need to secure another manufacturer, and it may take as long as 12 months to transfer instrument manufacturing. An interruption in the manufacturing of these instruments could have a material adverse effect on our results of operations. +Additionally, one third party manufactures a certain reagent for use with our Alethia assays. While alternative suppliers exist, we elect to utilize this third party exclusively in order to maintain consistency in our materials, which is critical in complying with FDA regulatory requirements. An interruption in the manufacturing of these reagents could have a material adverse effect on our results of operations. +- 16 - +Table of Contents +Finished Products +We outsource the manufacturing for certain finished diagnostic products to third parties. A disruption in the supply of these finished products could have a material adverse effect on our business until we find another supplier or bring manufacturing +in-house. +Four products manufactured exclusively for us by two separate and independent companies accounted for 6%, 7% and 11% of consolidated net revenues in 2021, 2020 and 2019, respectively. Meridian owns all rights and title to the FDA 510(k) clearances for these products. +Activities undertaken by Meridian to reduce the risk of these sole-supplier arrangements include maintaining adequate inventory levels, supplier qualification procedures, supplier audits, site visits, and frequent communication. Additionally, we have identified potential alternate suppliers. +Our ability to meet future customer demand for selected products is dependent upon our ability to successfully manage our manufacturing capacity and supply chains. +To manage our anticipated future growth effectively, it may become necessary for us to enhance our manufacturing and supply chain capabilities, infrastructure and operations, information technology infrastructure, and financial and accounting systems and controls. Organizational growth and +scale-up +of operations could strain our existing managerial, operational, financial, and other resources. If our management is unable to effectively prepare for our expected future growth, our expenses may increase more than anticipated, our net revenues could grow more slowly than expected, and we may not be able to achieve our commercialization, profitability, or product development goals. Our failure to effectively implement the necessary processes and procedures and otherwise prepare for our anticipated growth could have a material adverse effect on our future consolidated financial condition and results of operations. +Increased prices for, poor quality of, or extended inability to source raw materials or services used in our products, and supply chain disruptions, could adversely affect profitability. +Our profitability is affected by the prices of the raw materials used in the manufacture of our products. These prices fluctuate based on a number of factors beyond our control, including changes in supply and demand, general economic conditions, labor costs, fuel-related delivery costs, competition, import duties, tariffs, currency exchange rates, and, in some cases, government regulation. Significant increases in the prices of raw materials, similar to the inflationary increases we have experienced in the second half of 2021, that cannot be recovered through increases in the price of our products and/or offset by savings in other areas, could adversely affect our results of operations and cash flows. +We cannot guarantee that the prices we are paying for raw materials today will continue in the future, or that the marketplace will continue to support current prices for our products, or that such prices can be adjusted to fully or partially offset raw material price increases in the future. Any increases in prices resulting from a tightening supply of these or other commodities could adversely affect our profitability. We do not engage in hedging transactions for raw material purchases, but we do enter into some fixed-price supply contracts. +Our dependency upon regular deliveries of supplies and the quality of those supplies upon delivery from particular suppliers means that interruptions, stoppages, or deterioration of quality in such deliveries could adversely affect our operations until arrangements with alternate suppliers could be made. Several of the raw materials used in the manufacture of our products currently are procured from a single source. In some cases, we also outsource certain services to suppliers, including but not limited to, engineering, assembly, shipping, and commissioning services. If a supplier were unable to deliver these materials or services, or if the quality of these materials or services declined, for an extended period of time as a result of financial difficulties, catastrophic events affecting their facilities, or other factors, including recent supply chain disruptions we have experienced, or if we were unable to negotiate acceptable terms for the supply of materials or services with these suppliers, our business could be adversely affected. We may not be able to find acceptable alternatives, and any such alternatives could result in increased costs. Extended inability to source a necessary raw material or service could cause us to cease manufacturing one or more products for a period of time, which could also lead to loss of customers, as well as reputational, competitive, or business harm, which could have a material adverse effect on our business, consolidated financial condition, and results of operations. +- 17 - +Table of Contents +Risks Related to Legal, Regulatory and International Matters +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +Medical device diagnostics is a highly regulated industry. We cannot provide assurance that we will be able to obtain necessary governmental clearances or approvals, or timely clearances or approvals, to market future products in the U.S. and other countries. Costs and difficulties in complying with laws and regulations administered by the FDA, the U.S. Department of Agriculture, the U.S. Department of Commerce, the U.S. Drug Enforcement Agency, the Centers for Disease Control and Prevention (“CDC”), or other regulators can result in unanticipated expenses and delays, and interruptions to the sale of new and existing products. +Regulatory approval can be a lengthy, expensive and uncertain process, making the timing and cost of approvals difficult to predict. Failure to comply with these regulations can result in delays in obtaining authorization to sell products, seizure or recall of products, suspension or revocation of authority to manufacture or sell products, and other civil or criminal sanctions. +If we or our third-party vendors fail to comply with FDA regulations relating to the manufacturing of our products or any component part, we may be subject to fines, injunctions and penalties, and our ability to commercially distribute and sell our products may be negatively impacted. +Our diagnostics manufacturing facilities, and the manufacturing facilities of any of our third-party diagnostic component manufacturers or critical suppliers, are required to comply with the FDA’s Quality System Regulation (“QSR”), which sets forth minimum standards for the procedures, execution and documentation of the design, testing, production, control, quality assurance, labeling, packaging, sterilization, storage, and shipping of the products we sell, and related regulations, including Medical Device Reporting (“MDR”) regulations regarding reporting of certain malfunctions and adverse events potentially associated with our products. The FDA may evaluate our compliance with the QSR, MDR and other regulations, among other ways, through periodic announced or unannounced inspections which could disrupt our operations and interrupt our manufacturing. If in conducting an inspection of our manufacturing facilities, or the manufacturing facilities of any of our third-party component manufacturers or critical suppliers, an FDA investigator observes conditions or practices believed to violate the QSR, the investigator may document their observations on a Form FDA 483 that is issued at the conclusion of the inspection. A manufacturer that receives an FDA 483 may respond in writing and explain any corrective actions taken in response to the inspectional observations. The FDA will typically review the facility’s written response and may +re-inspect +to determine the facility’s compliance with the QSR and other applicable regulatory requirements. Failure to take adequate and timely corrective actions to remedy objectionable conditions listed on an FDA 483 could result in the FDA taking administrative or enforcement actions. Among these may be the FDA’s issuance of a Warning Letter to a manufacturer, which informs it that the FDA considers the observed violations to be of “regulatory significance” that, if not corrected, could result in further enforcement action. +FDA enforcement actions, which include seizure, injunction, criminal prosecution, and civil penalties, could result in total or partial suspension of a facility’s production and/or distribution, product recalls, fines, suspension of the FDA’s review of product applications, and/or the FDA’s issuance of adverse publicity. Thus, an adverse inspection could force a shutdown of our manufacturing operations or a recall of our products. Adverse inspections could also delay FDA approval of our products and could have an adverse effect on our production, net revenues and profitability. +We and any of our third-party vendors may also encounter other problems during manufacturing including failure to follow specific protocols and procedures, equipment malfunction, and environmental factors, any of which could delay or impede our ability to meet demand. The manufacture of our product also subjects us to risks that could harm our business, including problems relating to our facilities and errors in manufacturing components that could negatively affect the efficacy or safety of our products or cause delays in shipment of our products. Any interruption or delay in the manufacture of the product, or any of its components, could impair our ability to meet the demand of our customers and cause them to cancel orders or switch to competitive products, which could, therefore, have a material adverse effect on our business, consolidated financial condition and results of operations. +- 18 - +Table of Contents +As described in Item 3. “Legal Proceedings”, on April 17, 2018, the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlines documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas calling for witnesses to testify before a federal grand jury related to this matter. The March 2021 subpoena was issued to a former employee of Magellan, and the April subpoena was issued to a current employee of Magellan. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. The Company cannot predict when the investigation will be resolved, the outcome of the investigation, or its potential impact on the Company. Approximately $2,803, $2,035 and $1,585 of expense for attorneys’ fees related to this matter is included within the Consolidated Statements of Operations for the years ended September 30, 2021, 2020 and 2019, respectively. +Magellan submitted 510(k) applications in December 2018, seeking to reinstate venous blood sample-types for its LeadCare II, LeadCare Plus and LeadCare Ultra testing systems. In February 2019 the FDA informed Magellan that each of these 510(k) applications had been put on Additional Information hold. On July 15, 2019, we provided responses to the FDA’s requests for Additional Information. These 510(k) applications have since expired and are no longer under FDA review. Further, while Magellan’s LeadCare testing systems remain cleared for marketing by the FDA and permitted for use with capillary blood samples, the FDA advised that it has commissioned a third-party study of the Company’s LeadCare testing systems using both venous and capillary blood samples. According to the FDA, the results of the field study will be used in conjunction with other information to determine whether further action by the FDA or the CDC is necessary to protect the public health. The Company intends to fully cooperate with the FDA or CDC on any +follow-up +based on the third-party study. +During October 2019, the FDA performed a +follow-up +inspection of Magellan’s manufacturing facility. The FDA issued five Form FDA 483 observations. On March 18, 2020, we participated in a regulatory meeting with the FDA at the FDA’s request to further discuss the Form FDA 483 observations and our remediation efforts. Since the inspection, we have submitted a number of written responses to the FDA regarding the five Form FDA 483 observations issued in the October 2019 inspection, and have worked diligently to execute a remediation plan. During October 2020, the FDA issued Establishment Inspection Reports which closed out the inspections from June 2017 and October 2019 under 21 C.F.R.20.64(d)(3). +During June 2021, the FDA performed an inspection of Magellan’s manufacturing facility. As a result of this inspection, the FDA issued one Form 483 observation. On August 3, 2021, FDA sent Magellan a +close-out +letter for the Warning Letter that FDA issued to Magellan on October 23, 2017. The FDA’s +close-out +letter notified Magellan that FDA has completed an evaluation of Magellan’s corrective actions in response to FDA’s Warning Letter, and based on FDA’s evaluation, Magellan has addressed the issues identified in the Warning Letter. FDA’s +close-out +letter also stated that future FDA inspections of Magellan and regulatory activities will further assess the adequacy and sustainability of Magellan’s corrections. +We incur costs and demands upon management as a result of complying with the laws and regulations affecting public companies in the U.S., and failure to comply with these laws could harm our business and the price of our common stock. +As a public company listed in the U.S., we incur significant legal, accounting and other expenses. In addition, changing laws, regulations and standards relating to corporate governance and public disclosure, including regulations implemented by the SEC, the Public Company Accounting Oversight Board (“PCAOB”) and the NASDAQ Global Select Market, may increase our legal and financial compliance costs and/or make some activities more time consuming. These laws, regulations and standards are subject to varying interpretations and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. If we fail to comply with new laws, regulations and standards, regulatory authorities may initiate legal proceedings against us, and our business may be harmed. +- 19 - +Table of Contents +We could be adversely affected by health care reform legislation. +Third-party payers for medical products and services, including state, federal and foreign governments, are increasingly concerned about escalating health care costs and can indirectly affect the pricing or the relative attractiveness of our products by regulating the maximum amount of reimbursement they will provide for diagnostic testing services. Following years of increasing pressure, during 2010 the U.S. government enacted comprehensive health care reform with the enactment of the Patient Protection and Affordable Care Act, as amended by the Health Care and Education Reconciliation Act, which made changes that significantly impact the pharmaceutical and medical device industries. The Protecting Access to Medicare Act of 2014 requires applicable laboratories to report all private payor reimbursement rates and the volumes for each test they perform. The statute requires that Medicare establish reimbursement rates based on the weighted median of private insurance reimbursement rates effective January 1, 2017. The new Medicare rates would be subject to a maximum reduction of 10% a year for the initial three-year period and a maximum of 15% a year for the subsequent three-year period. There is no limit on the amount of potential rate increases. As a result, some of our customers in the U.S. may experience lower Medicare reimbursement rates for our products, which may adversely affect our business, financial condition and results of operations. We are seeing some effect on the reimbursement rates for our products. If reimbursement amounts for diagnostic testing services decrease further in the future, such decreases may reduce the amount that will be reimbursed to hospitals or physicians for such services and consequently, could place constraints on the levels of overall pricing, which could have a material effect on our net revenues and results of operations. +Additional state and federal health care reform measures may be adopted in the future, any of which could have a material adverse effect on our ability to successfully commercialize our products and on our industry in general. For example, the U.S. government has in the past considered, is currently considering, and may in the future consider, health care policies and proposals intended to curb rising health care costs, including those that could significantly affect both private and public reimbursement for health care services. Further, state and local governments, as well as a number of foreign governments, are also considering or have adopted similar types of policies. Future significant changes in the health care system in the U.S. or elsewhere, and current uncertainty about whether and how changes may be implemented, could have a negative impact on the demand for our products. We are unable to predict whether health care policies, including policies stemming from legislation or regulations affecting our business, may be proposed or enacted in the future, what effect such policies would have on our business, or the effect that ongoing uncertainty about these matters will have on the purchasing decisions of our customers. +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +Any reductions in government health care spending or research funding in an effort to reduce the U.S. federal deficit could result in reduced demand for our products or additional pricing pressure. Further, there is ongoing uncertainty regarding the federal budget and federal spending levels, including the possible impacts of a failure to increase the “debt ceiling.” Any U.S. government default on its debt could have broad macroeconomic effects that could, among other things, raise our borrowing costs. Any future shutdown of the federal government or failure to enact annual appropriations could also have a material adverse impact on our consolidated financial condition, and results of operations. +Global market, political, environmental, and economic conditions, including those related to the financial markets, could have a material adverse effect on our operating results, financial condition, and liquidity. +Our business is sensitive to changes in general economic, political and environmental conditions, both inside and outside the U.S. Conditions such as the following, among others, may create additional risk to our results of operations: (i) continuing uncertainties in the eurozone; (ii) the effects of climate change regulation; (iii) the global effects of the ongoing +COVID-19 +pandemic, including the Emergency Temporary Standard (“ETS”) +COVID-19 +workplace vaccination and testing mandate from the Occupational Safety and Health Administration (“OSHA”); (iv) unanticipated implications from the voluntary exit of the U.K. from the EU; and (v) uncertainties in China and emerging markets. +Instability in the global economy and financial markets can adversely affect our business in several ways, including limiting our customers’ ability to obtain sufficient credit or pay for our products within the terms of sale. Competition could further intensify among the manufacturers and distributors with whom we compete for volume and market share, resulting in lower net revenue due to steeper discounts and product +mix-down. In +particular, if certain key or sole suppliers were to become capacity constrained or insolvent, it could result in a reduction or interruption in supplies or a significant increase in the price of supplies. +- 20 - +Table of Contents +The U.K. left the EU on January 31, 2020. While all EU rules and laws continued to apply to the U.K. through the transition period, which ended December 31, 2020, the U.K. and the EU reached a free trade agreement on December 24, 2020, which was ratified on April 28, 2021 and went into effect on May 1, 2021. The agreement includes regulatory and customs cooperation mechanisms, as well as provisions supporting open and fair competition. Under the trade agreement, the U.K. is free to set its own trade policy and can negotiate with other countries that do not currently have free trade deals with the EU. Although the full impact of the trade agreement is uncertain, it is possible that the recent changes to the trading relationship between the U.K. and the EU due to the trade agreement could result in increased cost of goods imported into and exported from the U.K., which may decrease the profitability of our operations. Additional currency volatility could drive a weaker British pound, which could increase the cost of goods imported into the U.K. and may decrease the profitability of our operations. A weaker British pound versus the U.S. dollar may also cause local currency results of our operations to be translated into fewer U.S. dollars during a reporting period. Given the lack of comparable precedent, it is unclear what financial, trade, regulatory and legal implications the trade agreement will have on our business; however, Brexit and its related effects could potentially have an adverse impact on our consolidated financial condition, and results of operations. +We depend on international net revenues, and our operating results may be adversely impacted by foreign currency, regulatory or other developments affecting international markets. +We sell products and services into approximately 70 countries. For fiscal 2021, approximately 40% of our consolidated net revenues were transacted in currencies other than the U.S. dollar. We are subject to the risks associated with fluctuations in the exchange rates for the Australian dollar, British pound, Canadian dollar, Chinese yuan, Euro, and New Israeli shekel. In addition, we have manufacturing operations, suppliers, and employees located outside the U.S. Since our growth strategy depends in part on our ability to further penetrate markets outside the U.S., we expect to continue to increase our revenue and presence outside the U.S., including in emerging markets. +Our international business is subject to risks that are often encountered in +non-U.S. +operations, including: +• +interruption in the transportation of materials to us and finished goods to our customers, including conditions where recovery from natural disasters may be delayed due to country-specific infrastructure and resources; +• +differences in terms of sale, including payment terms; +• +local product preferences and product requirements; +• +changes in a country’s or region’s political or economic condition, including with respect to safety and health issues; +• +trade protection measures and import or export licensing requirements; +• +unexpected changes in laws or regulatory requirements, including unfavorable changes with respect to tax, trade or sanctions compliance matters; +• +limitations on ownership and on repatriation of earnings and cash; +• +difficulty in staffing and managing widespread operations; +• +differing labor regulations; +• +difficulties in enforcing contract and property rights under local law; +• +difficulties in implementing restructuring actions on a timely or comprehensive basis; and +• +differing protection of intellectual property. +Such risks may be more likely or pronounced in emerging markets, where our operations may be subject to greater uncertainty due to increased volatility associated with the developing nature of their economic, legal, and governmental systems. +If we are unable to successfully manage the risks associated with expanding our global business or to adequately manage operational fluctuations, it could adversely affect our business, financial condition, or results of operations. +- 21 - +Table of Contents +New tariffs and other trade measures could adversely affect our operating results. +The current U.S. administration has expressed strong concerns about imports from countries that it perceives as engaging in unfair trade practices, and it is possible the administration could impose import duties or other restrictions on products, components or raw materials sourced from those countries, which may include countries from which we import components or raw materials. We are currently not aware of any new import duties imposed on our products. Any such new import duties or restrictions could have a material adverse effect on our business, results of operations or financial condition. Moreover, these new tariffs, or other changes in U.S. trade policy, could trigger retaliatory actions by affected countries. Certain foreign governments have instituted or are considering imposing trade sanctions on certain U.S. goods. +Other foreign governments are considering the imposition of sanctions that will deny U.S. companies access to critical raw materials. A “trade war” of this nature or other governmental actions related to tariffs or international trade agreements or policies has the potential to adversely impact demand for our products, our costs, customers, manufacturers, suppliers and/or the economic environments in which we operate and, thus may adversely impact our businesses. In addition, there may be changes to existing trade agreements, like the North American Free Trade Agreement (“NAFTA”) and its anticipated successor agreement, the U.S.-Mexico-Canada Agreement (“USMCA”), which is still subject to approval by the U.S., Mexico and Canada, greater restrictions on free trade generally, and significant increases in tariffs on goods imported into the U.S., particularly tariffs on products manufactured in Mexico, among other possible changes. It remains unclear what the U.S. administration or foreign governments will or will not do with respect to tariffs, NAFTA, USMCA or other international trade agreements and policies. Any changes to NAFTA (or subsequent trade agreements) could impact our operations in countries where we manufacture or sell products, or source components or materials, which could adversely affect our business and results of operations. +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and may have to limit or cease sales of our products. +The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We currently carry product liability insurance at a level we believe is commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. In certain customer contracts, we indemnify third parties for certain product liability claims related to our products. These indemnification obligations may cause us to pay significant sums of money for claims that are covered by these indemnifications. In addition, a defect in the design or manufacture of our products could have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our results of operations. +Risks Related to Our Common Stock +The market price of our common stock may be volatile and fluctuate significantly, which could result in substantial losses for stockholders and subject us to litigation. +The market price of our common stock may be subject to significant fluctuations due to numerous factors, including but not limited to the risks described in this “Risk Factors” section. In addition, the stock market in general, the NASDAQ Global Market and the market for diagnostics companies in particular may experience a loss of investor confidence. A loss of investor confidence may result in extreme price and volume fluctuations in our common stock that are unrelated or disproportionate to the operating performance of our business, financial condition or results of operations. These broad market and industry factors may materially harm the market price of our common stock and expose us to securities class-action litigation. Class-action litigation, even if unsuccessful, could be costly to defend and divert management’s attention and resources, which could further materially harm our consolidated financial condition and results of operations. +- 22 - +Table of Contents +Our business could be negatively impacted as a result of shareholder activism, an unsolicited takeover proposal or a proxy contest. +In recent years, proxy contests and other forms of stockholder activism have been directed against numerous public companies. If a proxy contest or an unsolicited takeover proposal is made with respect to us, we could incur significant costs in defending our company, which would have an adverse effect on our financial results. Shareholder activists may also seek to involve themselves in the governance, strategic direction and operations of our company. Such proposals may disrupt our business and divert the attention of our management and employees, and any perceived uncertainties as to our future direction resulting from such a situation could result in the loss of potential business opportunities, be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel and business partners, all of which could adversely affect our business. In addition, actions of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business. +The authority of our board to issue preferred stock and the effects of certain provisions of Ohio corporation law may discourage takeover bids. +Our board of directors has the authority to issue up to 1,000 shares of undesignated preferred stock and to determine the rights, preferences, privileges and restrictions, including voting rights, of such shares without any future vote or action by the shareholders. The issuance of preferred stock under certain circumstances could have the effect of delaying or preventing a change in control of our company. Ohio corporation law contains provisions that may discourage takeover bids for our company that have not been negotiated with the board of directors. Such provisions could limit the price that investors might be willing to pay in the future for shares of our common stock. In addition, sales of substantial amounts of shares in the public market could adversely affect the market price of our common stock and our ability to raise additional capital at a price favorable to us. +General Risk Factors +One or more cybersecurity incidents may adversely impact our financial condition, results of operations and reputation. +Our operations involve the use of multiple systems that process, store and transmit sensitive information about our customers, suppliers, employees, financial position, operating results and strategies. We face global cybersecurity risks and threats on a continual and ongoing basis, which include, but are not limited to, attempts to access systems and information, computer viruses, or +denial-of-service +attacks. These risks and threats range from uncoordinated individual attempts to sophisticated and targeted measures. While we are not aware of any material cyber-attacks or breaches of our systems to date, we have and continue to implement measures to safeguard our systems and information and mitigate potential risks, including employee training around phishing, malware and other cyber risks, but there is no assurance that such actions will be sufficient to prevent cyber-attacks or security breaches that manipulate or improperly use our systems, compromise sensitive information, destroy or corrupt data, or otherwise disrupt our operations. The occurrence of such events, including breaches of our security measures or those of our third-party service providers, could negatively impact our reputation and our competitive position and could result in litigation with third parties, regulatory action, loss of business due to disruption of operations and/or reputational damage, potential liability and increased remediation and protection costs, any of which could have a material adverse effect on our consolidated financial condition and results of operations. In an effort to mitigate the financial impact such an attack might have on the Company, we maintain cyber liability insurance coverage. However, such coverage may be insufficient to cover the full impact of a cyber-attack. Additionally, as cybersecurity risks become more sophisticated, we may need to increase our investments in security measures which could have a material adverse effect on our consolidated financial condition and results of operations. +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +Our future success depends on our continued ability to attract, hire and retain highly qualified personnel, including our executive officers and scientific, technical, sales and marketing employees, and their ability to manage growth successfully. If such key employees were to leave and we were unable to obtain adequate replacements, our results of operations could be adversely affected. +- 23 - +Table of Contents +Our bank credit agreement imposes restrictions with respect to our operations, which could adversely impact our business. +Our bank credit agreement contains a number of financial covenants that require us to meet certain financial ratios and tests. If we fail to comply with the obligations in the credit agreement, we would be in default under the credit agreement. If an event of default is not cured or waived, it could result in acceleration of any indebtedness under our credit agreement, which could have a material adverse effect on our business. At September 30, 2021, we had $60,000 outstanding on a $160,000 bank revolving credit facility. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Our corporate offices are located in the Village of Newtown, a suburb of Cincinnati, Ohio. Our Newtown campus includes sites for diagnostic test manufacturing and distribution, immunoassay research and development and administrative functions. Our Newtown campus also includes a new facility where we are expanding and automating our Revogene diagnostic test device manufacturing. We also have diagnostic test manufacturing and distribution sites in Billerica, Massachusetts (blood-chemistry), Modi’in, Israel (BreathID and BreathTek urea breath testing systems), and Quebec City, Quebec, Canada (Revogene diagnostic test device and instrument manufacturing). Our sites in Billerica, Modi’in and Quebec City also include research and development functions. We also operate a Diagnostics sales and distribution center near Milan, Italy and rent office space in Paris, France and +Braine-l’Alleud, +Belgium for sales and administrative functions, and space in Manasquan, New Jersey and Changzhou, China to house BreathID technical service and repair functions. +Our Life Science operations are conducted in several facilities in Memphis, Tennessee; Boca Raton, Florida; London, England; Luckenwalde, Germany; Sydney, Australia; and Beijing, China. Manufacturing of molecular reagents occurs in our London and Luckenwalde sites. Manufacturing of immunoassay reagents occurs in our Memphis and Boca Raton sites. Our site in London also includes our primary research and development function. +ITEM 3. +LEGAL PROCEEDINGS +We are a party to various litigation matters that we believe are in the normal course of business. Aside from the matters discussed below, the ultimate resolution of these matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows, and no material provision has been made in the Consolidated Financial Statements for these matters. +On April 17, 2018, the Company’s wholly owned subsidiary Magellan received a subpoena from the DOJ regarding its LeadCare product line. The subpoena outlines documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas calling for witnesses to testify before a federal grand jury related to this matter. The March 2021 subpoena was issued to a former employee of Magellan, and the April subpoena was issued to a current employee of Magellan. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. The Company cannot predict when the investigation will be resolved, the outcome of the investigation, or its potential impact on the Company. Approximately $2,803, $2,035 and $1,585 of expense for attorneys’ fees related to this matter is included within the Consolidated Statements of Operations for 2021, 2020 and 2019, respectively. See “Lead Testing Matters” beginning on page 29 within MD&A. +- 24 - +Table of Contents +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +PART II. +ITEM 5. +MARKET FOR REGISTRANT’S COMMON +EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock trades on the NASDAQ Global Select Market under the symbol VIVO. +Holders of our Common Stock +As of September 30, 2021, there were approximately 550 holders of record and approximately 24,030 beneficial owners of our common shares. +Dividends +During 2019, the Company suspended the payment of its quarterly cash dividend, which had previously been established at an indicated annual cash dividend rate of $0.50 per share for fiscal 2019. The dividend was suspended as part of the Company’s regular evaluation of its capital allocation, with the action taken in order to deploy cash into new product development activities and to preserve capital resources and liquidity for general corporate purposes. Any declaration and amount of dividends will be determined by the board of directors in its discretion based upon its evaluation of earnings, cash flow requirements, business developments and opportunities, and any other factors the board of directors determines are relevant to its evaluation. At this time, we do not expect to resume paying cash dividends. We paid dividends of $0.25 per common share in 2019. +Stock Total Return Performance +The graph below compares the cumulative +5-Year +total return realized by shareholders on Meridian Bioscience, Inc.’s common stock relative to the cumulative total returns of the NASDAQ Composite index and two customized peer groups of six companies and ten companies, respectively, whose individual companies are listed in footnotes 1 and 2 below. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock, in the index and in each of the peer groups (including reinvestment of dividends) on September 30, 2016, and its relative performance is tracked through September 30, 2021. +1. +The six companies included in the Company’s first customized peer group (“2020 Peer Group”) are: +Bio-Rad +Laboratories, Inc., bioMerieux S.A., Myriad Genetics, Inc., OraSure Technologies, Inc., Quidel Corporation, and Trinity Biotech Plc. +2. +The ten companies included in the Company’s second customized peer group (“2021 Peer Group”) are: +Bio-Rad +Laboratories, Inc., +Bio-Techne +Corporation, bioMerieux S.A., DiaSorin S.p.a., Hologic, Inc., Myriad Genetics, Inc., OraSure Technologies, Inc., Qiagen N.V., Quidel Corporation, and Trinity Biotech Plc. +- 25 - +Table of Contents +ITEM 6. +INTENTIONALLY OMITTED +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Refer to “Note About Forward-Looking Statements” following the Index in front of this Form +10-K +and Item 1A “Risk Factors” on pages 11 through 24 of this Annual Report. +In the discussion that follows, all dollar amounts are in thousands (both tables and text), except per share data +. +The purpose of Management’s Discussion and Analysis is to provide an understanding of the financial condition, changes in consolidated financial condition and results of operations of Meridian Bioscience, Inc. (“Meridian”, the “Company”, “We”). This discussion should be read in conjunction with the Consolidated Financial Statements and notes. It should be noted that the terms revenue and/or revenues are utilized throughout the Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) to indicate net revenue and/or net revenues. In addition, throughout the MD&A, we refer to certain product tradenames and trademarks, which are protected under applicable intellectual property laws and are our property. Solely for convenience, these tradenames and trademarks are referred to without the +® +or +™ +symbols, but such references are not intended to indicate in any way that we will not assert, to the fullest extent of the law, our rights to these tradenames and trademarks. +- 26 - +Table of Contents +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations for infectious disease products in Cincinnati, Ohio; Quebec City, Canada; and Modi’in, Israel; and manufacturing operations for blood chemistry products in Billerica, Massachusetts (near Boston). These diagnostic test products are sold and distributed in the countries comprising North and Latin America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, or “ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; and Luckenwalde, Germany, and the sale and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, isothermal mixes, enzymes, nucleotides, and bioresearch reagents domestically and abroad, including a sales and business development facility, with outsourced distribution capabilities, in Beijing, China to further pursue growing revenue opportunities in Asia. +Recent Developments +Impact of +COVID-19 +Pandemic +During the latter half of fiscal 2020 and throughout fiscal 2021, the +COVID-19 +pandemic has had both positive and negative effects on our business. +Our Life Science segment’s products have been well positioned to respond to in vitro device (“IVD”) manufacturers’ needs for reagents for molecular, rapid antigen and serology tests. Consequently, our Life Science segment grew its revenues over 100% in fiscal 2020 and delivered record operating income and margin, demonstrating what this segment could achieve at a much larger scale. This higher-than-historical level of growth in the Life Science segment continued in fiscal 2021, with full year revenues, operating income and operating margin increasing 43%, 67% and nine percentage points, respectively. +Our Diagnostics segment, on the other hand, has been negatively impacted by the health systems’ increased focus on +COVID-19 +testing over traditional infectious disease testing. The impacts of the +COVID-19 +pandemic are most dramatically evident in the 34% year-over-year decline in revenues from respiratory illness assays in fiscal 2021, following flat year-over-year revenue levels being experienced in fiscal 2020. +Despite these recent +COVID-19 +pandemic related trends, due to the many uncertainties surrounding the +COVID-19 +pandemic, we can provide no assurances with respect to our views of the longevity, severity or impacts to our consolidated financial condition of the ongoing +COVID-19 +pandemic. +Employee Safety +While our employee base in the U.S. has returned to working +on-site +at our facilities, we have recently implemented a hybrid work-from-home program for certain personnel, and we continue to utilize a work-from-home process as needed on a +site-by-site +basis outside the U.S. for those employees whose +on-site +presence has been deemed to be +non-essential. +We have also implemented enhanced cleaning and sanitizing procedures and provided additional personal hygiene supplies at all our sites. We have implemented policies for employees to adhere to Centers for Disease Control and Prevention (“CDC”) guidelines on social distancing, and similar guidelines by authorities outside the U.S. To date, we have been able to manufacture and distribute products globally, and all our sites have continued to operate with little, if any, impact on shipments to customers to date. As the +COVID-19 +pandemic continues, along with continuing governmental restrictions which vary by locale and jurisdiction, there is an increased risk of employee absenteeism, which could materially impact our operations at one or more sites. To date, the steps we have taken, including our work-from-home processes, have not materially impacted the Company’s financial reporting systems, internal controls over financial reporting or disclosure controls. +Supply Chains +Supply chains supporting our products have generally remained intact, providing access to sufficient inventory of the key materials needed for manufacturing. To date, delays and allocations for raw materials have been limited and have not had a material impact on our results of operations. From time to time, we identify alternative suppliers to address the risk of a current supplier’s inability to deliver materials in volumes sufficient to meet our manufacturing needs; or we may choose to purchase certain materials in bulk volumes where we have supply chain scarcity concerns. It remains possible that we may experience some sort of interruption to our supply chains, and such an interruption could materially affect our ability to timely manufacture and distribute our products and unfavorably impact our results of operations. See LeadCare product recall discussion beginning on page 29. +- 27 - +Table of Contents +Product Development and Clinical Trials +Our Diagnostics segment’s new product development programs are progressing at a slower pace than normal, in part, as the prevalence of certain infectious diseases has been much lower than normal during the +COVID-19 +pandemic. For example, the relative lack of a respiratory illness season in 2020-2021 has significantly impacted the availability of influenza samples, thereby affecting the pace of development of our molecular respiratory panel for the Revogene system. These matters continue to impact our timing for filing applications for product clearances with the U.S. Food and Drug Administration (“FDA”), as well as related timing of FDA clearances of such filings. Additionally, the ongoing +COVID-19 +pandemic has slowed and could continue to slow down our efforts to expand our product portfolio through acquisitions and distribution opportunities, impacting the speed with which we are able to bring additional products to market. +Product Demand +Our Life Science segment manufactures, markets and sells a number of molecular and immunological reagents to IVD customers, including those who are making both molecular and immunoassay +COVID-19 +tests. Since late in the second quarter of fiscal 2020, we have generally experienced unprecedented demand for certain of our molecular reagents (e.g., ribonucleic acid (“RNA”) master mixes and nucleotides), including a resurgence in such demand during our fiscal 2021 fourth quarter. While we are expecting a continuation of this trend for the foreseeable future, this expectation will certainly be impacted by infection rates and the responses to such levels of infection varying by country based on their individual +COVID-19 +case statistics, infection rates and vaccine programs. We believe that our reagent products for +COVID-19 +have applications in many alternative, +non-hospital-based +channels (e.g., airports, schools, etc.). Our products are used in over 200 regulatory agency approved +COVID-19 +related assays around the world. +COVID-19 +related reagent revenues totaled approximately $111,900 and $71,500 for the years ended September 30, 2021 and 2020, respectively. +Our Diagnostics segment manufactures, markets and sells a number of molecular, immunoassay, blood chemistry and urea breath tests +for various infectious diseases and blood-lead levels. Sales volumes for a number of these assays have been adversely affected by the +COVID-19 +pandemic over the past year and half, as such assays are often used in +non-critical +care settings. However, we have seen indications of a return to more normal pre-pandemic levels, including with respect to our respiratory illness assays during the fourth quarter of 2021. The +COVID-19 +pandemic also has depressed instrument orders and placements for our BreathID, Curian and Revogene platforms. Order activity for our Revogene platform was affected by the delay in obtaining emergency use authorization (“EUA”) for our +SARS-CoV-2 +assay, as we believe customers have taken a “wait and see” approach throughout our entire EUA application process, which culminated in receipt of the EUA on November 9, 2021. This follows our voluntary withdrawal of the application on February 23, 2021 and its resubmission on June 25, 2021. Despite the situation encountered with our EUA application for the +SARS-CoV-2 +assay, we have proceeded with the process of increasing our capacity to produce these tests, as well as other tests on the Revogene system, at our facilities in Quebec and Cincinnati. Specifically, we are: (i) adding a second production line at our Quebec manufacturing facility; and (ii) installing two additional production lines in a leased facility near our corporate headquarters in Cincinnati. With approximately $10,900 expended in the year ended September 30, 2021, it is expected that these expansion efforts will be completed during calendar 2021 at a total cost of approximately $19,600, which is expected to be partially offset by the $5,500 National Institutes of Health Rapid Acceleration of Diagnostics (“RADx”) initiative grant entered into on February 1, 2021, $1,500 of which had been received as of September 30, 2021 (see Note 14, +“National Institutes of Health Contracts” +of the Consolidated Financial Statements). +Impact of Brexit +The United Kingdom (“U.K.”) left the European Union (“EU”) on January 31, 2020. While all EU rules and laws continued to apply to the U.K. through the transition period, which ended December 31, 2020, the U.K. and the EU reached a free trade agreement on December 24, 2020, which was ratified on April 28, 2021 and went into effect on May 1, 2021. The agreement includes regulatory and customs cooperation mechanisms, as well as provisions supporting open and fair competition. Under the trade agreement, the U.K. is free to set its own trade policy and can negotiate with other countries that do not currently have free trade deals with the EU. Although the full impact of the trade agreement is uncertain, it is possible that the recent changes to the trading relationship between the U.K. and the EU due to the trade agreement could result in increased cost of goods imported into and exported from the U.K., which may decrease the profitability of our operations. Additional currency volatility could drive a weaker British pound, which could increase the cost of goods imported into the U.K. and may decrease the profitability of our operations. A weaker British pound versus the U.S. dollar may also cause local currency results of our operations to be translated into fewer U.S. dollars during a reporting period. Given the lack of comparable precedent, it is unclear what financial, trade, regulatory and legal implications the trade agreement will have on our business; however, Brexit and its related effects could potentially have an adverse impact on our consolidated financial position and results of operations. +- 28 - +Table of Contents +The U.K.’s withdrawal from the EU could also adversely impact the operations of our vendors and of our other partners. Our management team has identified areas of concern and implemented strategies to help mitigate these concerns. It is possible that these strategies may not be adequate to mitigate any adverse impacts of Brexit, and that these impacts could further adversely affect our business and results of operations. +Lead Testing Matters +On September 1, 2021, the Company’s wholly owned subsidiary Magellan announced the expansion of the Class I voluntary recall of its LeadCare test kits for the detection of lead in blood, which it had initiated in May 2021 after identifying an ongoing issue with the testing controls included in certain manufactured lots of its LeadCare test kits. As a result of the identified issue, impacted test kit lots could potentially underestimate blood lead levels when processing patient blood samples. The Company is working closely with the FDA in its execution of the recall activities, which include Magellan notifying customers and distributors affected by the recall and providing instructions for the return of impacted test kits. Although evaluation of the recall and the related notification process is ongoing, approximately $5,100 has been estimated and accrued as of September 30, 2021, to cover the currently anticipated costs of the recall. In total, approximately $5,600 of recall-related expense has been included within the Consolidated Statement of Operations for the year ended September 30, 2021. Anticipated recall-related costs primarily include product replacement and/or refund costs, mailing/shipping costs, attorneys’ fees and other miscellaneous costs. +As described in Item 3. “Legal Proceedings”, on April 17, 2018, the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlines documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas calling for witnesses to testify before a federal grand jury related to this matter. The March 2021 subpoena was issued to a former employee of Magellan, and the April subpoena was issued to a current employee of Magellan. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. The Company cannot predict when the investigation will be resolved, the outcome of the investigation, or its potential impact on the Company. Approximately $2,803, $2,035 and $1,585 of expense for attorneys’ fees related to this matter is included within the Consolidated Statements of Operations for the years ended September 30, 2021, 2020 and 2019, respectively. +Magellan submitted 510(k) applications in December 2018, seeking to reinstate venous blood sample-types for its LeadCare II, LeadCare Plus and LeadCare Ultra testing systems. In the second fiscal quarter of 2019 the FDA informed Magellan that each of these 510(k) applications had been put on Additional Information hold. On July 15, 2019, we provided responses to the FDA’s requests for Additional Information. These 510(k) applications have since expired and are no longer under FDA review. Further, while Magellan’s LeadCare testing systems remain cleared for marketing by the FDA and permitted for use with capillary blood samples, the FDA advised that it has commissioned a third-party study of the Company’s LeadCare testing systems using both venous and capillary blood samples. According to the FDA, the results of the field study will be used in conjunction with other information to determine whether further action by the FDA or the CDC is necessary to protect the public health. The Company intends to fully cooperate with the FDA or CDC on any +follow-up +based on the third-party study. +During October 2019, the FDA performed a +follow-up +inspection of Magellan’s manufacturing facility. The FDA issued five Form FDA 483 observations. On March 18, 2020, we participated in a regulatory meeting with the FDA at the FDA’s request to further discuss the Form FDA 483 observations and our remediation efforts. Since the inspection, we have submitted a number of written responses to the FDA regarding the five Form FDA 483 observations issued in the October 2019 inspection, and have worked diligently to execute a remediation plan. During October 2020, the FDA issued Establishment Inspection Reports which closed out the inspections from June 2017 and October 2019 under 21 C.F.R.20.64(d)(3). +- 29 - +Table of Contents +During June 2021, the FDA performed an inspection of Magellan’s manufacturing facility. As a result of this inspection, the FDA issued one Form 483 observation. On August 3, 2021, FDA sent Magellan a +close-out +letter for the Warning Letter that FDA issued to Magellan on October 23, 2017. FDA’s +close-out +letter notified Magellan that FDA has completed an evaluation of Magellan’s corrective actions in response to FDA’s Warning Letter, and based on FDA’s evaluation, Magellan has addressed the issues identified in the Warning Letter. FDA’s +close-out +letter also stated that future FDA inspections of Magellan and regulatory activities will further assess the adequacy and sustainability of Magellan’s corrections. +Results of Operations +Fourth Quarter +Net earnings for the fourth quarter of fiscal 2021 increased 3% to $6,657, or $0.15 per diluted share, from net earnings for the fourth quarter of fiscal 2020 of $6,493, or $0.15 per diluted share. The level of net earnings in the fourth quarter of fiscal 2021 was adversely affected by approximately $5,600, or $0.10 per diluted share, of LeadCare product recall expenses and a $4,596, or $0.08 per diluted share, upward adjustment to the fair value of acquisition consideration related to GenePOC, offsetting the impact of higher revenues and resulting gross profit. Other key events occurring in the fourth quarter of 2021 include the acquisition of the BreathTek business in July 2021 and the August 2021 settlement of the contingent acquisition consideration related to GenePOC (see Note 4, +“Business Combinations” +and Note 3, +“Fair Value Measurements” +of the Consolidated Financial Statements, respectively). +Consolidated revenues for the fourth quarter of fiscal 2021 totaled $76,204, an increase of 19% compared to the fourth quarter of fiscal 2020 (17% increase on a constant-currency basis). +Revenues from the Diagnostics segment for the fourth quarter of fiscal 2021 increased 15% to $34,301, compared to the fourth quarter of fiscal 2020 (also 15% increase on a constant-currency basis), comprised of a 22% increase in molecular assay products and a 14% increase in +non-molecular +assay products. The fourth quarter of fiscal 2021 represents the second consecutive quarter our Diagnostics segment has shown positive revenue growth versus the same quarter of fiscal 2020, an achievement not experienced since the early stages of the +COVID-19 +pandemic. Our Diagnostics segment generated an $11,900 operating loss for the fourth quarter of fiscal 2021, a $7,700 larger operating loss than the fourth quarter of fiscal 2020, largely due to the aforementioned $5,600 of LeadCare product recall expenses and $4,596 upward adjustment to the fair value of acquisition consideration related to GenePOC. +With a 16% increase in revenues from molecular reagents products and a 33% increase in revenues from immunological reagents products, revenues for our Life Science segment increased 22% to $41,903 during the fourth quarter of fiscal 2021 compared to the fourth quarter of fiscal 2020. On a constant-currency basis, revenues for the Life Science segment increased 19%. Life Science segment revenues reflect an increase in demand from diagnostic test manufacturers for the reagents utilized in +COVID-19 +related tests. Revenue from sales of our core Life Science segment products (other than +COVID-19 +related contributions) experienced growth of approximately $1,800, or 11%, compared to the fourth quarter of fiscal 2020. This growth resulted in large part from obtaining business from +COVID-19 +customers who are now using our products for other +non-COVID-19 +related purposes, as well as a rebound in volumes of core immunological products. Our Life Science segment generated $23,200 of operating income, or a margin of 55%, for the fourth quarter of fiscal 2021, an increase of $6,000 from the fourth quarter of fiscal 2020. +Fiscal Year +Net earnings for fiscal 2021 increased 55% to $71,407, or $1.62 per diluted share, from net earnings for fiscal 2020 of $46,186, or $1.07 per diluted share. The level of net earnings in fiscal 2021 was affected predominantly by the strong increase in revenues and operating income in our Life Science segment, stemming primarily from the demand for reagents used in +COVID-19 +related tests. +Consolidated revenues for fiscal 2021 totaled $317,896, an increase of 25% compared to fiscal 2020 (22% increase on a constant-currency basis). +- 30 - +Table of Contents +Diagnostics segment revenues increased 5% to $127,760 in fiscal 2021 (4% increase on a constant-currency basis), comprised of a 13% decrease in molecular assay products and a 10% increase in +non-molecular +assay products. Our Diagnostics segment generated an $8,100 operating loss in fiscal 2021, compared to operating income of $3,900 in fiscal 2020. This year over year decline in operating income resulted primarily from the combined effects of: (i) lower gross profit margins, as detailed in the “Gross Profit” section below; (ii) the aforementioned $5,600 of LeadCare product recall expenses in fiscal 2021; and (iii) the $6,293 decrease in the fair value of contingent acquisition consideration related to GenePOC included in fiscal 2020 and settled in fiscal 2021 (as discussed above). These factors contributing to the decline in operating margin were partially offset by the decrease in acquisition costs resulting from the Exalenz transaction in fiscal 2020. +With a 66% increase in revenues from molecular reagents products and a 10% increase in revenues from immunological reagents products, revenues for our Life Science segment increased 43% to $190,136 during fiscal 2021 compared to fiscal 2020. On a constant-currency basis, revenues for the Life Science segment increased 38%. Fiscal 2021 Life Science segment revenues reflect a significant increase in sales of key molecular components such as RNA master mixes and deoxyribonucleotide triphosphates (“dNTPs”) to diagnostic test manufacturers for use in +COVID-19 +related PCR tests. Also contributing to the increased revenue levels during fiscal 2021 were sales of monoclonal antibody pairs used in +COVID-19 +antigen tests and, to a lesser degree, recombinant antigens used in +COVID-19 +antibody tests. In addition, revenue from sales of our core Life Science segment products (other than +COVID-19 +contributions) experienced growth of approximately $16,100, or approximately 26%. This growth resulted in large part from obtaining business from +COVID-19 +customers who are now using our products for other +non-COVID-19 +related purposes, as well as a rebound in volumes in core immunological products. Our Life Science segment generated $115,300 of operating income in fiscal 2021, an increase of $46,400 over fiscal 2020. +REVENUE OVERVIEW +Below are analyses of the Company’s revenue, by reportable segment, provided for each of the following: +- By Geographic Region +- By Product Platform/Type +Revenue Overview – By Reportable Segment & Geographic Region +Revenues for the Diagnostics segment, in the normal course of business, may be affected from year to year by buying patterns of major distributors and reference laboratories, seasonality and severity of seasonal diseases and outbreaks (including the +COVID-19 +pandemic), and foreign currency exchange rates. Revenues for the Life Science segment, in the normal course of business, may be affected from year to year by buying patterns of major IVD manufacturing customers, severity of disease outbreaks (including the +COVID-19 +pandemic), and foreign currency exchange rates. The +COVID-19 +pandemic contributed $111,900 of new revenue for our Life Science segment during fiscal 2021, and $71,500 during fiscal 2020. +See Note 2, +“Revenue Recognition” +of the Consolidated Financial Statements for detailed revenue disaggregation information. +Following is a discussion of the revenues generated by these product platforms/types and/or disease states: +Diagnostics Segment Products +The Diagnostics segment’s overall 5% growth in revenue during fiscal 2021 primarily results from the combined effects of the following: +• +Volume growth in the gastrointestinal product family benefitting from: (i) a full year of revenue from sales of BreathID instruments and tests, acquired in the April 2020 Exalenz acquisition; and (ii) two months of revenue from sales of the BreathTek product, acquired in late July 2021; +• +Ongoing pricing pressure on our +H. pylori +stool antigen tests, which contributed approximately $2,700 of unfavorable price variance from customers in the U.S.; +- 31 - +Table of Contents +• +Volume declines from sales of respiratory illness products, comprised of tests for Group A Strep, Mycoplasma pneumonia, Influenza, and Pertussis, among others, reflecting the decreased focus on testing for these illnesses throughout the +COVID-19 +pandemic; and +• +Volume declines from sales of blood chemistry products due to the ongoing LeadCare product recall, which commenced in May 2021 ($2,136 decrease in revenue in fiscal 2021, compared to fiscal 2020). +Life Science Segment Products +The tripling of the Life Science segment’s revenues since fiscal 2019, including the 43% year-over-year growth in revenue during fiscal 2021, primarily results from the combined effects of the following: +• +Unprecedented demand for the Life Science segment’s products by diagnostic test manufacturers for use in +COVID-19 +related tests, resulting in +COVID-19-related +reagent revenues totaling $111,900 in fiscal 2021, compared to approximately $71,500 in fiscal 2020; and +• +Revenue from core Life Science products increasing approximately 26% over fiscal 2020, due in large part from obtaining business from +COVID-19 +customers who are now using our products for +non-COVID-19 +related purposes, as well as a rebound in volumes of core immunological product sales. +Foreign Currency +Fluctuations in foreign currency exchange rates in fiscal 2021 compared to fiscal 2020 had an approximate $9,200 favorable impact on fiscal 2021 consolidated net revenues; $1,300 within the Diagnostics segment and $7,900 within the Life Science segment. This compares to +year-to-year +currency exchange rates having an approximate $1,250 unfavorable impact on consolidated net revenues in fiscal 2020; $150 within the Diagnostics segment and $1,100 within the Life Science segment. +Significant Customers +Revenue concentrations related to certain customers within our Diagnostics and Life Science segments are set forth in Note 15, +“Reportable Segments and Major Concentration Data” +of the Consolidated Financial Statements. +Gross Profit: +2021 +2020 +2021 vs. 2020 +Inc (Dec) +Gross Profit +$ +201,148 +$ +156,248 +29 +% +Gross Profit Margin +63 +% +62 +% +1 point +Overall gross profit margins during both fiscal 2021 and 2020 have been favorably impacted by greater contributions from our Life Science segment’s molecular reagent products, which are some of our highest margin products. During fiscal 2021, which included the peak of the +COVID-19 +pandemic, approximately 41% of consolidated revenues related to sales of molecular reagent products, compared to approximately 31% during fiscal 2020. +Overall gross profit margins in fiscal 2021 have been unfavorably impacted in our Diagnostics segment by production capacity +ramp-up +and scrap costs in our Quebec facility, where Revogene instruments and test devices are made, inventory reserve provisions for short-dated products stemming from depressed sales levels during the +COVID-19 +pandemic, and the impacts of the previously discussed LeadCare product recall (see “Lead Testing Matters” above). +- 32 - +Table of Contents +Operating Expenses — +Segment Detail and Corporate +Research & +Development +Selling & +Marketing +General & +Administrative +Other +(1)(2) +Total Operating +Expenses +Fiscal 2020: +Diagnostics +$ +21,454 +$ +21,172 +$ +23,233 +$ +(1,916 +) +$ +63,943 +Life Science +2,275 +5,314 +11,755 +200 +19,544 +Corporate +— +— +9,357 +2,080 +11,437 +Total 2020 Expenses +$ +23,729 +$ +26,486 +$ +44,345 +$ +364 +$ +94,924 +Fiscal 2021: +Diagnostics +$ +21,406 +$ +21,430 +$ +24,915 +$ +5,079 +$ +72,830 +Life Science +2,505 +5,350 +13,265 +— +21,120 +Corporate +— +— +11,361 +2,803 +14,164 +Total 2021 Expenses +$ +23,911 +$ +26,780 +$ +49,541 +$ +7,882 +$ +108,114 +(1) +Diagnostics segment fiscal 2020 reflects negative expense amount due to $6,293 adjustment to fair value of the acquisition consideration related to GenePOC. +(2) +LeadCare product recall expenses are included within the Diagnostics segment’s fiscal 2021 Other expenses. +Operating expenses in fiscal 2021 increased $13,190 to $108,114. Major components of this increase were as follows: +• +$5,600 in LeadCare product recall expenses within our Diagnostics segment; +• +$1,400 increase in purchase accounting amortization within our Diagnostics segment, stemming from both the Exalenz and BreathTek acquisitions; +• +a full year of administrative expenses within our Diagnostics segment related to the Exalenz acquisition completed in April 2020; +• +higher commercial insurance costs for Directors & Officers and Property & Casualty coverages within Corporate; and +• +the adjustment to the fair value of the acquisition consideration as the result of the settlement in fiscal 2021 resulting in a $5,384 year-over-year increase in expense within our Diagnostics segment. +Offsetting these increases was lower spending for acquisition transaction costs, stemming from the Exalenz acquisition. +Operating Income +Operating income increased 52% in fiscal 2021, following an 88% increase in fiscal 2020, as a result of the factors discussed above. +Other Expense +Other expense, net primarily includes interest costs on the Company’s long-term borrowings and contingent grant obligations due to the Israel Innovation Authority, currency gains and losses, and in fiscal 2021, grant income under the RADx initiative (see Note 14, +“National Institutes of Health Contracts” +of the Consolidated Financial Statements). Interest costs related to the revolving credit facility with a commercial bank were $1,420 and $2,464 in fiscal 2021 and 2020, respectively. The varying levels of interest costs on the revolving credit facility reflect the following approximate levels of average debt outstanding, as detailed in Note 10, +“Bank Credit Arrangements” +of the Consolidated Financial Statements: (i) fiscal 2021 - $56,505; and (ii) fiscal 2020 - $74,560. +- 33 - +Table of Contents +Income Taxes +The effective rate for income taxes was 21% and 22% for fiscal 2021 and 2020, respectively. The decline in effective tax rates relates primarily to the increasing allocations of taxable income in certain foreign jurisdictions with tax rates lower than the U.S., particularly the U.K. Additionally, the fiscal 2021 effective rate was favorably impacted by a larger-than-prior-year effect of current year restricted share unit lapses and stock option exercises occurring on dates when the share price of Company stock was significantly higher than the share price on the date such equity awards were granted. +Impact of Inflation +To the extent feasible, we have consistently followed the practice of reviewing our prices to consider the impacts of inflation on salaries and fringe benefits for employees and the cost of purchased materials and services. Inflation and changing prices did not have a material adverse impact on our gross margin, revenues or operating income in fiscal 2021 or 2020. +Liquidity and Capital Resources +: +Liquidity +Our cash flow and financing requirements are determined by analyses of operating and capital spending budgets and debt service. We have historically maintained a credit facility to augment working capital requirements and to respond quickly to acquisition opportunities. +We have an investment policy that guides the holdings of our investment portfolio, which presently consists of bank savings accounts and institutional money market mutual funds. Our objectives in managing the investment portfolio are to: (i) preserve capital; (ii) provide sufficient liquidity to meet working capital requirements and fund strategic objectives such as acquisitions; and (iii) capture a market rate of return commensurate with market conditions and our policy’s investment eligibility criteria. As we look forward, we will continue to manage the holdings of our investment portfolio with preservation of capital being the primary objective. +We intend to continue to fund our working capital requirements from current cash flows from operating activities and cash on hand, and such sources are anticipated to be adequate to fund working capital requirements, capital expenditures and debt service during the next twelve months. However, if needed, we also have an additional source of liquidity through the amount remaining available on our $160,000 bank revolving credit facility, which totaled $100,000 as of September 30, 2021. The Company also maintains a shelf registration statement on file with the SEC. Our liquidity needs may change if overall economic conditions worsen and/or liquidity and credit within the financial markets tightens for an extended period, and such conditions impact the collectability of our customer accounts receivable, impact credit terms with our vendors, or disrupt the supply of raw materials and services. +As of September 30, 2021, our cash and cash equivalents balance was $49,771 or $3,743 lower than at the end of fiscal 2020. This modest decrease primarily results from generating $66,865 of cash flow from operations, an increase of 39% over fiscal 2020, and the use of cash to fund certain rather significant uses of cash during the year, most notably the following: +(i) +payment of consideration holdback and contingent consideration settlement related to the fiscal 2019 GenePOC acquisition ($25,000); +(ii) +acquisition of the BreathTek business, net of $1,000 holdback ($18,585); +(iii) +funding of capital expenditures, which were primarily comprised of manufacturing expansion related to Revogene, net of $1,500 RADx grant monies received ($16,812); and +(iv) +net paydown on revolving credit facility and Israeli government grant obligations ($8,824 and $5,297, respectively). +Considering these factors, our balance of net debt (defined as bank debt, government grant obligations and total contingent obligations related to acquisitions, net of cash and cash equivalents +on-hand) +decreased approximately $36,300 to approximately $17,000 at September 30, 2021. +- 34 - +Table of Contents +Capital Resources +As described in Note 10, +“Bank Credit Arrangements” +of the Consolidated Financial Statements, the Company maintains a $160,000 credit facility, which is secured by substantially all our U.S. assets and includes certain restrictive financial covenants. This credit facility was amended in October 2021 to increase its capacity to $200,000 and extend its term to October 25, 2026. The Company also maintains a shelf registration statement on file with the SEC. +Our capital expenditures totaled $18,312 for fiscal 2021, $1,500 of which was offset by receipts under the RADx grant initiative (see Note 14, +“National Institutes of Health Contracts” +of the Consolidated Financial Statements), and which largely related to expanding manufacturing capacity. During fiscal 2022 our capital expenditures are estimated to total approximately $15,000, comprised of approximately $12,000 and $3,000 in the Diagnostics and Life Science segments, respectively. Included within the Diagnostics segment capital expenditures estimate is approximately $8,700 related to completion of the manufacturing capacity +scale-up +and automation initiatives for Revogene assay production. Such expenditures may be funded with cash and cash equivalents on hand, operating cash flows, and/or availability under the $200,000 revolving credit facility discussed above. In addition, a portion of the Diagnostics segment expansion may be funded by $4,000 remaining under the previously noted RADx grant entered into on February 1, 2021 (see Note 14, +“National Institutes of Health Contracts” +of the Consolidated Financial Statements). +Contractual Obligations +: +In addition to the obligations related to the above-noted revolving credit facility and the contingent government grant obligations detailed in Note 10, +“Bank Credit Arrangements” +and Note 13, +“Contingent Obligations and +Non-Current +Liabilities” +of the Consolidated Financial Statements, respectively, the Company’s contractual obligations and their related due dates were as follows as of September 30, 2021: +Total +Less than 1 +Year +1-3 Years +4-5 Years +More than +5 Years +Operating leases +(1) +$ +6,239 +$ +2,194 +$ +2,736 +$ +1,244 +$ +65 +Purchase obligations +(2) +51,295 +49,537 +1,554 +204 +— +Acquisition price holdback +(3) +1,000 +— +1,000 +— +— +Uncertain income tax positions liability and interest +(4) +870 +870 +— +— +— +Total +$ +59,404 +$ +52,601 +$ +5,290 +$ +1,448 +$ +65 +(1) +Meridian and its subsidiaries are parties to a number of operating lease agreements around the world, the majority of which relate to office and warehouse building leases expiring at various dates. +(2) +Purchase obligations relate primarily to outstanding purchase orders for machinery and equipment, inventory, including instruments, service items, and research and development activities. These contractual commitments are not in excess of expected production requirements over the next twelve months. +(3) +Pursuant to the purchase agreement related to the July 31, 2021 acquisition of the BreathTek business, Meridian’s remaining consideration to be paid totals $1,000 and is comprised solely of a purchase price holdback. +(4) +Due to inherent uncertainties in the timing of settlement of tax positions, we are unable to estimate the timing of the effective settlement of these obligations. +- 35 - +Table of Contents +Other Commitments and +Off-Balance +Sheet Arrangements +: +License Agreements +Meridian has entered into various license agreements that require payment of royalties based on a specified percentage of sales of related products, with such percentages generally ranging from approximately 3% to 10%. During fiscal 2021, royalty expense totaled approximately $5,200, with 25% and 75% of such expense relating to our Diagnostics and Life Science segments, respectively. This compares to a total of approximately $1,850 of royalty expense in fiscal 2020, with 81% and 19% relating to our Diagnostics and Life Science segments, respectively. Meridian expects that payments under these agreements will amount to approximately $3,000 in fiscal 2022. +Off-Balance +Sheet Arrangements +We utilize foreign currency exchange forward contracts to limit exposure to volatility in foreign currency gains and losses related to financial assets denominated in other than the holding subsidiary’s functional currency. These contracts are generally settled within a +30-day +time frame and are not formally designated or accounted for as accounting hedges. We also utilize interest rate swap agreements to limit exposure to volatility in the LIBOR interest rate in connection with the revolving credit facility. The interest rate swap agreements are designated and accounted for as accounting hedges (see Note 3, +“Fair Value Measurements” +of the Consolidated Financial Statements). Aside from these instruments, we do not utilize special-purpose financing vehicles or have any material undisclosed +off-balance +sheet arrangements. +Market Risk Exposure +: +Foreign Currency Risk +We have market risk exposure related to foreign currency transactions from our operations outside the U.S., as well as certain suppliers to our domestic businesses located outside the U.S. The foreign currencies where we have market risk exposure are the Australian dollar, British pound, Canadian dollar, Chinese yuan, Euro, and New Israeli shekel. Assessing foreign currency exposures is a component of our overall ongoing risk management process, with such currency risks managed as we deem appropriate. +Concentration of Customers/Products Risk +Our Diagnostics segment’s revenues from sales to three customers were 33% and 32% of the Diagnostics segment’s total net revenues for fiscal 2021 and 2020, respectively, or 13% and 15% of consolidated net revenues in each fiscal year. Additionally, our three major Diagnostics segment product families – gastrointestinal, respiratory illnesses and blood chemistry – accounted for 80% and 82% of our Diagnostics segment’s net revenues during fiscal 2021 and 2020, respectively, or 32% and 39% of each year’s consolidated net revenues. +Our Life Science segment’s revenues from sales to three diagnostics manufacturing customers were 22% and 30% of the Life Science segment’s total net revenues for fiscal 2021 and 2020, respectively or 13% and 16% of consolidated net revenues in each fiscal year. Additionally, sales of products related to +COVID-19 +accounted for 59% and 54% of our Life Science segment’s net revenues during fiscal 2021 and 2020, respectively, or 35% and 28% of each year’s consolidated net revenues. +Critical Accounting Policies +: +The Consolidated Financial Statements included in this Form +10-K +have been prepared in accordance with U.S. generally accepted accounting principles. Such accounting principles require management to make judgments about estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Listed below are the accounting policies management believes to be critical to understanding the Consolidated Financial Statements, along with reference to location of the policy discussion within the Consolidated Financial Statements. The listed policies are considered critical due to the fact that application of such polices requires the use of significant estimates and assumptions, and the carrying values of related assets and liabilities are material. +- 36 - +Table of Contents +Accounting Policy +Location +Within Consolidated +Financial Statements +Examples of Key Estimate Assumptions +Goodwill +Note 1(h) +Discounted cash flow assumptions (e.g., long-term growth rates, discount rate, EBITDA) +Revenue Recognition +Note 1(i) +Distributor price adjustments and fee accruals +Income Taxes +Note 1(l) and Note 11 +Uncertain positions and state apportionment factors +Recent Accounting Pronouncements +: +A description of accounting pronouncements recently adopted by the Company, as well as accounting pronouncements issued but not yet adopted by the Company, are set forth in Note 1(s), +“Summary of Significant Accounting Policies- Recent Accounting Pronouncements” +of the Consolidated Financial Statements. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +See Capital Resources and Market Risk Exposure above within Item 7, beginning on page 35. +- 37 - +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements +Management’s Report on Internal Control over Financial Reporting +39 +Reports of Independent Registered Public Accounting Firms +40 +Consolidated Statements of Operations for the years ended September 30, 2021, 2020 and 2019 +44 +Consolidated Statements of Comprehensive Income for the years ended September 30, 2021, 2020 and 2019 +45 +Consolidated Statements of Cash Flows for the years ended September 30, 2021, 2020 and 2019 +46 +Consolidated Balance Sheets as of September 30, 2021 and 2020 +47 +Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2021, 2020 and 2019 +49 +Notes to Consolidated Financial Statements +50 +Schedule No. II – Valuation and Qualifying Accounts for the years ended September 30, 2021, 2020 and 2019 +80 +All other supplemental schedules are omitted due to the absence of conditions under which they are required or because the information is shown in the Consolidated Financial Statements or Notes thereto. +- 38 - +Table of Contents +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act +Rule 13a-15(f). +The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of September 30, 2021, based on the framework and criteria in the 2013 +Internal Control – Integrated Framework, +issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on management’s evaluation and those criteria, the Company concluded that its system of internal control over financial reporting was effective as of September 30, 2021. +The Company’s independent registered public accounting firm has issued an attestation report on the registrant’s internal control over financial reporting. +/s/ Jack Kenny +/s/ Bryan T. Baldasare +Jack Kenny +Bryan T. Baldasare +Chief Executive Officer +Executive Vice President and +November 23, 2021 +Chief Financial Officer +November 23, 2021 +- 39 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Shareholders and the Board of Directors of Meridian Bioscience, Inc. +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheet of Meridian Bioscience, Inc. (the Company) as of September 30, 2021, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and the related notes and consolidated financial statement schedule listed in the Index to Annual Report on Form 10-K at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2021, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 23, 2021, expressed an unqualified opinion thereon. +Basis for Opinion +These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates. +Evaluation of Goodwill Impairment for the Diagnostics Reporting Unit +Description of the Matter +At September 30, 2021, the Company has recorded goodwill of $94.9 million within the Diagnostics reporting unit (within the Diagnostics reportable segment). As discussed in Note 1 to the consolidated financial statements, goodwill is tested for impairment annually at the beginning of the fourth quarter, or more frequently if indicators of potential impairment exist. Auditing management’s annual goodwill impairment test related to Diagnostics reporting unit was especially challenging due to the complexity of forecasting the long-term cash flows of the Diagnostics reporting unit and the estimation uncertainty of certain assumptions included within such forecasts. The estimation uncertainty was primarily due to the sensitivity of the Diagnostic reporting unit’s fair value to changes in the significant assumptions used in the income approach, such as forecasted net revenues, earnings before interest, taxes, depreciation and amortization (EBITDA) margins, long-term growth rates, and discount rates. These significant assumptions require a high degree of estimation and judgment based on an evaluation of historical performance, current industry and macroeconomic conditions. +- 40 - +Table of Contents +How We Addressed the Matter in Our Audit +We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s annual goodwill impairment process, including controls over management’s review of the significant assumptions described above and controls over management’s review of its financial forecasts and carrying value of the Diagnostics reporting unit. +To test the estimated fair value of the Diagnostics reporting unit, we performed audit procedures that included, among others, involving an internal valuation specialist to assist in our evaluation of the methodologies and certain significant assumptions used by the Company. We assessed the reasonableness of the Company’s assumptions around forecasted net revenues, EBITDA margins, long-term growth rates, and discount rates by comparing those assumptions to recent historical performance, current economic and industry trends, and financial forecasts. We also assessed the reasonableness of estimates included in the Company’s Diagnostics reporting unit financial forecast by evaluating how such assumptions compared to economic, industry, and peer expectations. We evaluated management’s historical accuracy of forecasting Diagnostics reporting unit net revenues and EBITDA margins by comparing past forecasts to subsequent actual activity. We performed various sensitivity analyses around these significant assumptions to understand the impact on the fair value calculation. +/s/ Ernst & Young LLP +We have served as the Company’s auditor since 2020. +Cincinnati, Ohio +November 23, 2021 +- 41 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +Opinion on the financial statements +We have audited the accompanying consolidated balance sheet of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the “Company”) as of September 30, 2020, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for the years ended September 30, 2020 and 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2020, and the results of its operations and its cash flows for the years ended September 30, 2020 and 2019, in conformity with accounting principles generally accepted in the United States of America. +Basis for opinion +These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ GRANT THORNTON LLP +We served as the Company’s auditor from 2005 to 2020. +Cincinnati, Ohio +November 23, 2020 +- 42 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Shareholders and the Board of Directors of Meridian Bioscience, Inc. +Opinion on Internal Control Over Financial Reporting +We have audited Meridian Bioscience, Inc.’s (the Company) internal control over financial reporting as of September 30, 2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2021, based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of September 30, 2021, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and the related notes and consolidated financial statement schedule listed in the Index to Annual Report on Form 10-K at Item 15 and our report dated November 23, 2021, expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. +Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ Ernst & Young LLP +Cincinnati, Ohio +November 23, 2021 +- 43 - +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2021 +2020 +2019 +Net Revenues +$ +317,896 +$ +253,667 +$ +201,014 +Cost of Sales +116,748 +97,419 +82,286 +Gross Profit +201,148 +156,248 +118,728 +Operating Expenses: +Research and development +23,911 +23,729 +17,760 +Selling and marketing +26,780 +26,486 +27,995 +General and administrative +49,541 +44,345 +34,044 +Product recall costs +5,596 +— +— +Selected legal costs +2,803 +2,080 +1,583 +Acquisition-related costs +392 +3,890 +1,808 +Change in fair value of acquisition +consideration +and settlement +( 909 +) +( 6,293 +) +— +Restructuring costs +— +687 +2,839 +Total Operating Expenses +108,114 +94,924 +86,029 +Operating Income +93,034 +61,324 +32,699 +Other Income (Expense): +Interest income +— +142 +681 +Interest expense +( 1,878 +) +( 2,632 +) +( 1,945 +) +RADx grant income +1,000 +— +— +Other, net +( 1,705 +) +459 +122 +Total Other Expense, Net +( 2,583 +) +( 2,031 +) +( 1,142 +) +Earnings Before Income Taxes +90,451 +59,293 +31,557 +Income Tax Provision +19,044 +13,107 +7,175 +Net Earnings +$ +71,407 +$ +46,186 +$ +24,382 +Earnings Per Share Data: +Basic earnings per common share +$ +1.65 +$ +1.08 +$ +0.57 +Diluted earnings per common share +$ +1.62 +$ +1.07 +$ +0.57 +Common shares used for basic earnings per common share +43,259 +42,855 +42,571 +Effect of dilutive stock options and restricted share units +753 +319 +328 +Common shares used for diluted earnings per common share +44,012 +43,174 +42,899 +Dividends declared per common share +$ +— +$ +— +$ +0.25 +Anti-Dilutive Securities: +Common share options and restricted share units +203 +893 +1,129 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 44 - +Table of Contents +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2021 +2020 +2019 +Net Earnings +$ +71,407 +$ +46,186 +$ +24,382 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +1,780 +3,884 +( 802 +) +Unrealized gain (loss) on cash flow hedge +510 +( 713 +) +( 1,159 +) +Reclassification of amortization of gain on cash flow hedge +( 154 +) +( 308 +) +( 102 +) +Income taxes related to items of other comprehensive income (loss) +( 78 +) +252 +465 +Other Comprehensive Income (Loss), Net of Tax +2,058 +3,115 +( 1,598 +) +Comprehensive Income +$ +73,465 +$ +49,301 +$ +22,784 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 45 - +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2021 +2020 +2019 +Cash Flows From Operating Activities +Net earnings +$ +71,407 +$ +46,186 +$ +24,382 +Non-cash items included in net earnings: +Depreciation of property, plant and equipment +6,510 +5,823 +5,433 +Amortization of intangible assets +8,776 +7,744 +4,531 +Stock compensation expense +4,156 +3,802 +3,251 +Deferred income taxes +( 3,835 +) +760 +( 817 +) +Losses on dispositions of long-lived assets +9 +64 +632 +Change in fair value of acquisition consideration and settlement +( 909 +) +( 6,293 +) +— +Change in the following, net of acquisitions: +Accounts receivable +( 12,766 +) +( 971 +) +( 2,215 +) +Inventories +( 7,800 +) +( 18,977 +) +3,841 +Prepaid expenses and other current assets +( 3,711 +) +( 153 +) +( 2,143 +) +Accounts payable and accrued expenses +6,346 +7,248 +( 2,315 +) +Income taxes payable +( 329 +) +1,435 +1,793 +Other, net +( 989 +) +1,308 +( 198 +) +Net cash provided by operating activities +66,865 +47,976 +36,175 +Cash Flows From Investing Activities +Purchase of property, plant and equipment +( 18,312 +) +( 3,299 +) +( 3,797 +) +RADx grant proceeds offsetting cost of equipment +1,500 +— +— +Payment of acquisition consideration holdback +( 5,000 +) +— +— +Disposals of property, plant and equipment +— +— +669 +Acquisitions, net of cash acquired and holdback +( 18,585 +) +( 51,299 +) +( 45,324 +) +Net cash used in investing activities +( 40,397 +) +( 54,598 +) +( 48,452 +) +Cash Flows From Financing Activities +Proceeds from revolving credit facility +10,000 +50,000 +75,824 +Payment of acquisition consideration +( 20,000 +) +— +— +Payment on revolving credit facility +( 18,824 +) +( 57,000 +) +— +Payment on government grant obligations +( 5,297 +) +— +— +Payment of debt issuance costs +— +( 116 +) +( 489 +) +Payments on term loan +— +— +( 50,250 +) +Proceeds from exercise of stock options +3,052 +3,559 +443 +Dividends paid +— +— +( 10,612 +) +Net cash (used in) provided by financing activities +( 31,069 +) +( 3,557 +) +14,916 +Effect of Exchange Rate Changes on Cash and Cash Equivalents +858 +1,296 +( 1,005 +) +Net (Decrease) Increase in Cash and Cash Equivalents +( 3,743 +) +( 8,883 +) +1,634 +Cash and Cash Equivalents at Beginning of Period +53,514 +62,397 +60,763 +Cash and Cash Equivalents at End of Period +$ +49,771 +$ +53,514 +$ +62,397 +Supplemental Cash Flow Information: +See Notes 1(g), 3, 9, 10 and 11. +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 46 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2021 +2020 +Assets +Current Assets: +Cash and cash equivalents +$ +49,771 +$ +53,514 +Accounts receivable, less allowances of $ 1,078 and $ 513 , respectively +53,568 +38,512 +Inventories, net +76,842 +61,264 +Prepaid expenses and other current assets +12,626 +8,900 +Total Current Assets +192,807 +162,190 +Property, Plant and Equipment: +Land +989 +991 +Buildings and improvements +32,765 +32,188 +Machinery, equipment and furniture +78,410 +69,854 +Construction in progress +9,991 +1,200 +Subtotal +122,155 +104,233 +Less: accumulated depreciation and amortization +78,941 +73,113 +Net Property, Plant and Equipment +43,214 +31,120 +Other Assets: +Goodwill +114,668 +114,186 +Other intangible assets, net +84,151 +83,197 +Right-of-use assets, net +5,786 +6,336 +Deferred income taxes +8,731 +7,647 +Other assets +365 +585 +Total Other Assets +213,701 +211,951 +Total Assets +$ +449,722 +$ +405,261 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 47 - +Table of Contents +CONSOLIDATED BALANCE SHEETS (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2021 +2020 +Liabilities and Shareholders’ Equity +Current Liabilities: +Accounts payable +$ +11,701 +$ +11,969 +Accrued employee compensation costs +16,853 +16,661 +Accrued product recall costs +5,100 +— +Current portion of acquisition consideration +— +12,619 +Current operating lease obligations +1,990 +1,789 +Current government grant obligations +638 +600 +Other accrued expenses +7,027 +5,362 +Income taxes payable +3,848 +3,524 +Total Current Liabilities +47,157 +52,524 +Non-Current Liabilities: +Acquisition consideration +1,000 +13,290 +Post-employment benefits +2,253 +2,493 +Fair value of interest rate swaps +203 +713 +Long-term operating lease obligations +3,932 +4,678 +Long-term debt +60,000 +68,824 +Government grant obligations +5,176 +10,524 +Long-term income taxes payable +469 +549 +Deferred income taxes +1,055 +3,804 +Other non-current liabilities +175 +233 +Total Non-Current Liabilities +74,263 +105,108 +Commitments and Contingencies +Shareholders’ Equity: +Preferred stock, no par value; 1,000,000 shares authorized; no ne issued +— +— +Common shares, no par value; 71,000,000 shares authorized, 43,361,898 and 43,068,842 issued, respectively +— +— +Additional paid-in capital +147,403 +140,195 +Retained earnings +180,701 +109,294 +Accumulated other comprehensive income (loss) +198 +( 1,860 +) +Total Shareholders’ Equity +328,302 +247,629 +Total Liabilities and Shareholders’ Equity +$ +449,722 +$ +405,261 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 48 - +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +Common +Shares +Issued +Additional +Paid-in +Capital +Retained +Earnings +Accum Other +Comp +(Loss) +Income +Total +Balance at September 30, 2018 +42,400 +$ +129,193 +$ +49,602 +$ +( 3,377 +) +$ +175,418 +Cash dividends paid - $ 0.250 per share +— +— +( 10,612 +) +— +( 10,612 +) +Conversion of restricted share units and exercise of stock options +312 +390 +— +— +390 +Stock compensation expense +— +3,251 +— +— +3,251 +Net earnings +— +— +24,382 +— +24,382 +Foreign currency translation adjustment +— +— +— +( 802 +) +( 802 +) +Hedging activity, net of tax +— +— +— +( 944 +) +( 944 +) +Adoption of ASU 2014-09 +— +— +( 116 +) +— +( 116 +) +Adoption of ASU 2018-02 +— +— +( 148 +) +148 +— +Balance at September 30, 2019 +42,712 +$ +132,834 +$ +63,108 +$ +( 4,975 +) +$ +190,967 +Conversion of restricted share units and exercise of stock options +357 +3,559 +— +— +3,559 +Stock compensation expense +— +3,802 +— +— +3,802 +Net earnings +— +— +46,186 +— +46,186 +Foreign currency translation adjustment +— +— +— +3,884 +3,884 +Hedging activity, net of tax +— +— +— +( 769 +) +( 769 +) +Balance at September 30, 2020 +43,069 +$ +140,195 +$ +109,294 +$ +( 1,860 +) +$ +247,629 +Conversion of restricted share units and exercise of stock options +293 +3,052 +— +— +3,052 +Stock compensation expense +— +4,156 +— +— +4,156 +Net earnings +— +— +71,407 +— +71,407 +Foreign currency translation adjustment +— +— +— +1,780 +1,780 +Hedging activity, net of tax +— +— +— +278 +278 +Balance at September 30, 2021 +43,362 +$ +147,403 +$ +180,701 +$ +198 +$ +328,302 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 4 +9 +- +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +Meridian Bioscience, Inc. and Subsidiaries +(in thousands, except per share data) +(1) +Summary of Significant Accounting Policies +(a) +Business Description +- Meridian is a fully-integrated life science company whose principal businesses are: (i) the development, manufacture, sale and distribution of diagnostic testing systems and kits, primarily for certain gastrointestinal and respiratory infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, isothermal mixes, enzymes, nucleotides, and bioresearch reagents used by other diagnostic manufacturers and researchers. +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of: (i) manufacturing operations for infectious disease products in Cincinnati, Ohio; Quebec City, Canada; and Modi’in, Israel; (ii) manufacturing operations for blood ch +e +mistry products in Billerica, Massachusetts (near Boston); and (iii) the sale and distribution of diagnostics products domestically and abroad. This segment’s products are used by hospitals, reference labs and physician offices to detect infectious diseases and elevated lead levels in blood. +The Life Science segment consists of: (i) manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; and Luckenwalde, Germany; and (ii) the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, isothermal reagents, nucleotides, and bioresearch reagents domestically and abroad, including a sales and business development facility, with outsourced distribution capabilities, in Beijing, China. This segment’s products are used by manufacturers and researchers in a variety of applications (e.g., in vitro medical device manufacturing, microRNA detection, next-generation sequencing, plant genotyping, and mutation detection, among others). +(b) +Principles of Consolidation and Basis of Presentation - +The Consolidated Financial Statements include the accounts of Meridian Bioscience, Inc. and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Unless the context requires otherwise, references to “Meridian,” “we,” “us,” “our” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +It should be noted that the terms revenue and/or revenues are utilized throughout these notes to the Consolidated Financial Statements to indicate net revenue and/or net revenues. +(c) +Use of Estimates - +The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of net revenues and expenses during the reporting period. The Company’s results are affected by economic, political, legislative, regulatory and legal actions. Economic conditions, such as recessionary trends, inflation, interest and monetary exchange rates, government fiscal policies, government policies surrounding the containment of the ongoing COVID-19 pandemic, and changes in prices of raw materials, can have a significant effect on the results of operations. Actual results could differ from the Company’s estimates. +(d) +Foreign Currency Translation +- Assets and liabilities of foreign operations are translated using year-end exchange rates with gains or losses resulting from translation included as a separate component of accumulated other comprehensive income (loss). Net revenues and expenses are translated using exchange rates prevailing during the year. We also recognize foreign currency transaction gains and losses on certain assets and liabilities that are denominated in the Australian dollar, British pound, Canadian dollar, Chinese yuan, Euro, and New Israeli shekel currencies. These gains and losses are included in other income (expense) in the Consolidated Statements of Operations. +- 50 - +Table of Contents +(e) +Cash and Cash Equivalents +- We consider short-term investments with original maturities of 90 days or less to be cash equivalents, including institutional money market funds. At times our investments of cash and cash equivalents with various high credit quality financial institutions may be in excess of the Federal Deposit Insurance Corporation (“FDIC”) insurance limit. +( +f) +Inventories +- Inventories are stated at the lower of cost or net realizable value. Cost is determined on a first-in, first-out (“FIFO”) basis. Diagnostic testing instruments are carried in inventory until they are sold outright or placed with a customer under the customer reagent rental program, at which time they are transferred to property, plant and equipment. +We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and other identified exposures. The Company specifically considered the impact of the ongoing COVID-19 pandemic on its inventories at September 30, 2021 and 2020. Such reserves were $ 4,997 and $ 3,629 at September 30, 2021 and 2020, respectively. We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and market conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. +(g) +Property, Plant and Equipment +- Property, plant and equipment are stated at cost. Upon retirement or other disposition, the cost and related accumulated depreciation are removed from the accounts and the resulting gain or loss is reflected in net earnings. Maintenance and repairs are expensed as incurred. Depreciation is computed on the straight-line method in amounts sufficient to write-off the cost over the estimated useful lives, generally as follows: +Buildings and improvements - 18 to 40 years +Leasehold improvements - life of the lease +Machinery, equipment and furniture - 3 to 10 years +Computer equipment and software - 3 to 5 years +Instruments under customer reagent rental arrangements - 5 years +Supplemental Cash Flow Information (Non-Cash Capital Expenditures) +Additions to property, plant and equipment for which cash remained unpaid +totaled $ 416 , $ 236 and $ 108 +at September 30, 2021, 2020 and 2019, respectively. +(h) +Intangible Assets - +Goodwill is subject to an annual impairment review (or more frequently if impairment indicators arise) at the reporting unit level, which has historically been performed as of the last day of the third fiscal quarter (June 30). During the third quarter of fiscal 2021, the Company decided to change the date of its annual goodwill impairment assessment from June 30 to July 1. The change was made to more closely align the annual goodwill impairment assessment date with the Company’s annual planning and budgeting process, as well as its long-term planning and forecasting process. The Company has determined this change in accounting principle is preferable and will not affect the Consolidated Financial Statements. Pursuant to the authoritative accounting literature, in fiscal 2021 the Company performed a goodwill impairment assessment as of the last day of its fiscal 2021 third quarter (June 30), as well as July 1, to ensure that the change in goodwill impairment assessment date did not delay or avoid an impairment charge. This change is not applied retrospectively, as it is impracticable to do so because retrospective application would require application of significant estimates and assumptions with the use of hindsight. Accordingly, the change will be applied prospectively. +At September 30, 2021, we had two reporting units (Diagnostics and Life Science), both of which contained goodwill. We review our reporting unit structure annually, or more frequently if facts and circumstances warrant. Goodwill is considered impaired if the carrying value of the reporting unit exceeds its fair value. We have no intangible assets with indefinite lives other than goodwill. +The historical annual impairment assessment of the Company’s goodwill as of June 30, 2021 +, +consisted of qualitative assessments for each of our Diagnostics and Life Science reporting units. A qualitative assessment is first performed to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value using qualitative indicators. In the event that the reporting unit does not pass the +- 51 - +Table of Contents +qualitative assessment, the reporting unit’s carrying value is compared to its fair value, with fair value of the reporting unit estimated using market value and discounted cash flow approaches. Both our Diagnostics and Life Science reporting units satisfied the qualitative assessments as of June 30, 2021, and no impairment was recognized. The updated annual goodwill impairment assessment of the Company’s goodwill as of July 1, +2021 +, +consisted of quantitative assessments for each of our Diagnostics and Life Science reporting units. The quantitative assessments determined fair value via both market (comparable company) and income (discounted cash flows) approaches. The key assumptions for the market and income approaches we use to determine fair value of our reporting units are updated at least annually. Those assumptions and estimates include macroeconomic conditions, competitive activities, cost containment, market data and market multiples, discount rates, and terminal growth rates, as well as future levels of net revenues growth and operating income margins, which are based upon the Company’s strategic plan. The strategic plan is updated as part of its annual planning process and is reviewed and approved by management and the Board of Directors. The strategic plan may be revised as necessary during a fiscal year, based on changes in market conditions or other changes in the reporting units. The discount rate assumption is based on the overall after-tax rate of return required by a market participant whose weighted-average cost of capital includes both equity and debt, including a risk premium. The discount rates may be impacted by adverse changes in the macroeconomic environment, including specifically the ongoing COVID-19 pandemic, volatility in the equity and debt markets, or other fact +o +rs. While the Company can implement and has implemented certain strategies to address these events, changes in operating plans or adverse changes in the future could reduce the underlying cash flows used to estimate reporting unit fair values and could result in a decline in fair value that would trigger a future impairment charge of the reporting unit’s goodwill balance. Based upon these approaches, the fair value of each reporting unit exceeded its carrying value; therefore, each of the Diagnostics and Life Science reporting units satisfied the quantitative assessment at July 1, 2021. The impact of the ongoing COVID-19 pandemic has had varying impacts on the Diagnostics and Life Science reporting units, and specifically an adverse impact on the Diagnostics reporting unit. However, even in light of the COVID-19 pandemic, the estimated fair value of the Diagnostics reporting unit, as calculated at July 1, 2021, +was over +50 % greater than +its +carrying value. +Long-lived assets, excluding goodwill, are reviewed for impairment when events or circumstances indicate that such assets may not be recoverable at their carrying value. Whether an event or circumstance triggers an impairment is determined by comparing an estimate of the asset’s future undiscounted cash flows to its carrying value. If impairment has occurred, it is measured by a fair-value based calculation. +Our ability to recover the carrying value of our identifiable intangible assets is dependent upon the future cash flows of the related assets. We make judgments and assumptions regarding future cash flows, including net revenues levels, gross profit margins, operating expense levels, working capital levels, and capital expenditures. With respect to identifiable intangible assets and fixed assets, we also make judgments and assumptions regarding useful lives. +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant under-performance relative to historical or projected operating results; (ii) negative industry trends; (iii) net revenues levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; and (v) other factors. If actual cash flows are less favorable than projections, this could trigger impairment of identifiable intangible assets and other long-lived assets. No triggering events have been identified by the Company for the years ended September 30, 2021, 2020 and 2019. +(i) +Revenue Recognition and Accounts Receivable +- +Revenue Recognition Policies +Product Sales +Revenue from contracts with customers is recognized in an amount that reflects the consideration we expect to receive in exchange for products when obligations under such contracts are satisfied. Revenue is generally recognized at a point-in-time when products are shipped, and control has passed to the customer. Such contracts can include various combinations of products that are generally accounted for as distinct performance obligations. +- 52 - +Table of Contents +Revenue is reduced in the period of sale for fees paid to distributors, which are inseparable from the distributor’s purchase of our product and for which we receive no goods or services in return. Revenue is reduced at the date of sale for product price adjustments payable to certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. Such accruals are netted against accounts receivable. +Shipping and handling costs incurred after control of the product is transferred to our customers are treated as fulfillment costs and not a separate performance obligation. +Our payment terms differ by jurisdiction and customer, but payment is generally required in a term ranging from 30 to 90 days from the date of shipment or satisfaction of the performance obligation . Accounts receivable are recorded in the Consolidated Balance Sheets at invoiced amounts less provisions for distributor price adjustments under local contracts and doubtful accounts. The allowance for doubtful accounts represents our estimate of probable credit losses and is based on historical write-off experience and known conditions that would likely lead to non-payment. Customer invoices are charged off against the allowance for doubtful accounts when we believe it is probable that the invoices will not be paid. The Company specifically considered the impact of the ongoing COVID-19 pandemic on its accounts receivable and determined there was no material impact on existing accounts receivable at September 30, 2021 +or +2020. +Practical Expedients and Exemptions +Revenue is recognized net of any taxes collected from customers (sales tax, value added tax, etc.), which are subsequently remitted to government authorities. +Our diagnostic assay products are generally not subject to a customer right of return except for product recall events under the rules and regulations of the U.S. Food and Drug Administration (“FDA”) or equivalent agencies outside the U.S. In this circumstance, the costs to replace or refund affected products would be accrued at the time a loss was probable and estimable. +We expense as incurred the costs to obtain contracts, as the amortization period would be one year or less. These costs, recorded within selling and marketing expense, include our internal sales force compensation programs and certain partner sales incentive programs, as we have determined that annual compensation is commensurate with annual selling activities. +Reagent Rental Arrangements +Certain of our Diagnostics segment’s product platforms require the use of instruments for the tests to be processed. In many cases, a customer is given use of the instrument provided they continue purchasing the associated tests, also referred to as “consumables” or “reagents”. If a customer stops purchasing the consumables, the instrument must be returned to us. Such arrangements are common practice in the diagnostics industry and are referred to as “Reagent Rentals”. Reagent Rentals may also include instrument related services such as a limited replacement warranty, training and installation. We concluded that the use of the instrument and related services (collectively known as “lease elements”) are not within the scope of Accounting Standards Codification (“ASC”) 606, +Revenue from Contracts with Customers +but rather ASC 842, +Leases +. Accordingly, we first allocate the transaction price between the lease elements and the non-lease elements based on estimates of relative standalone selling prices. Lease revenue is derived solely from the sale of consumables and is therefore recognized monthly as earned, which coincides with the transfer of control of the non-lease elements. +For the portion of the transaction price allocated to the non-lease elements, which are principally the test kits, the related revenue is recognized at a point-in-time when control transfers. +(j) +Fair Value Measurements +- Certain assets and liabilities are recorded at fair value in accordance with ASC 820-10, +Fair Value Measurements and Disclosures +. ASC 820-10 defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820-10 establishes a three-level hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy level assigned to each asset and liability is based on the assessment of the +- 53 - +Table of Contents +transparency and reliability of the inputs used in the valuation of such items at the measurement date based on the lowest level of input that is significant to the fair value measurement. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). +Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories based on inputs: +Level +1 +Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities +Level +2 +Quoted prices in markets that are not active and financial instruments for which all significant inputs are observable, either directly or indirectly +Level +3 +Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable +(k) +Research and Development Costs +- Research and development costs are charged to expense as incurred. Research and development costs include, among other things, salaries and wages for research scientists, materials and supplies used in the development of new products, costs for development of instrumentation equipment, costs for clinical trials, costs of regulatory compliance activities, and costs for facilities and equipment. +(l) +Income Taxes +- The provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for t +a +x purposes. These differences are adjusted to actual upon filing of our tax returns, typically occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +The Company has certain deferred income tax assets in select jurisdictions. The recoverability of these deferred income tax assets is assessed periodically, and valuation allowances are recognized if it is determined that it is more likely than not that the benefits will not be realized. When performing the assessment, the Company considers the ability to carryback losses to prior tax periods, future taxable income, the reversal of existing temporary differences, and tax planning strategies. +We account for uncertain tax positions using a benefit recognition model with a two-step approach: (i) a more-likely-than-not recognition criterion; and (ii) a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50 % likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit is recorded. We recognize accrued interest related to unrecognized tax benefits as a portion of our income tax provision in the Consolidated Statements of Operations. +(m) +Stock-Based Compensation +- We recognize compensation expense for all share-based awards made to employees based upon the fair value of the share-based award on the date of the grant. +(n) +Comprehensive Income (Loss) +- Comprehensive income (loss) represents the net change in shareholders’ equity during a period from sources other than transactions with shareholders. As reflected in the Consolidated Statements of Comprehensive Income, our comprehensive income is comprised of net earnings, foreign currency translation, +unrealized gain (loss) on our current cash flow hedge, +unrecognized gain (loss) on termination of our previous cash flow hedge, and the income taxes thereon. +- 54 - +Table of Contents +(o) +Shipping and Handling Costs +- Shipping and handling costs invoiced to customers are included in net revenues. Costs to distribute products to customers, including freight costs, warehousing costs, and other shipping and handling activities are included in cost of sales. +(p) +Non-Income Government-Assessed Taxes +- We classify all non-income, government-assessed taxes (sales, use and value-added) collected from customers and remitted by us to appropriate revenue authorities, on a net basis (excluded from net revenues) in the Consolidated Statements of Operations. +(q) +Acquisitions +- Assets and liabilities associated with business acquisitions are recorded at fair value, using the acquisition method of accounting. The Company allocates the purchase price of acquisitions based upon the fair value of each component, which may be derived from observable or unobservable inputs and assumptions. The Company may utilize third-party valuation specialists to assist us in this allocation. Initial purchase price allocations are preliminary and subject to revision within the measurement period, generally not to exceed one year from the date of acquisition. +(r) +Other income (expense), net - +Other +income (expense), net, consists principally of transaction currency gains or losses. When a transaction is denominated in a currency other than the subsidiary’s functional currency, the Company recognizes a transaction gain or loss in other income (expense), net within the Consolidated Statements of Operations when the transaction is settled. +(s) +Recent Accounting Pronouncements +- +Pronouncements Adopted +On October 1, 2020, the Company adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-13, +Measurement of Credit Losses on Financial Instruments +, which changed the impairment model used to measure credit losses for most financial assets. Use of the new forward-looking expected credit loss model for our accounts receivable valuation, rather than the previously utilized incurred credit loss model, did not have a material impact on the Consolidated Financial Statements. +Pronouncements Issued but Not Yet Adopted as of September 30, 2021 +In March 2020, the FASB issued ASU 2020-04, +Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting +, to provide temporary optional guidance relating to reference rate reform, particularly as it relates to easing the potential burden resulting from the expected discontinuation of the London Interbank Offered Rate (“LIBOR”). The guidance provides practical expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met, which may be applied through December 31, 2022. The Company is currently evaluating ASU 2020-04 but does not expect its application to have a material impact on the Consolidated Financial Statements. +In December 2019, the FASB issued ASU 2019-12, +Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes +(“ASU 2019-12”). ASU 2019-12 clarifies and simplifies accounting for income taxes by eliminating certain exceptions for intra-period tax allocation principles, the methodology for calculating income tax rates in an interim period, and recognition of deferred taxes for outside basis differences in an investment, among other updates. ASU 2019-12 will be effective for the Company’s fiscal year beginning on October 1, 2021. +The Company +is currently evaluating ASU 2019-12 +but does not expect its application to have a material impact on the Consolidated Financial Statements. +- 55 - +Table of Contents +(2) +Revenue Recognition +The following tables present our net revenues disaggregated by major geographic region, major product platform and disease state (Diagnostics +segment +only): +Net Revenues by Reportable Segment & Geographic Region +Year Ended September 30, +2021 +2020 +2019 +Diagnostics- +Americas +$ +101,293 +$ +97,228 +$ +110,109 +EMEA +24,475 +21,826 +23,888 +ROW +1,992 +2,078 +2,685 +Total Diagnostics +127,760 +121,132 +136,682 +Life Science- +Americas +46,063 +37,391 +19,441 +EMEA +93,655 +58,125 +28,850 +ROW +50,418 +37,019 +16,041 +Total Life Science +190,136 +132,535 +64,332 +Consolidated +$ +317,896 +$ +253,667 +$ +201,014 +Net Revenues by Product Platform/Type +Year Ended September 30, +2021 +2020 +2019 +Diagnostics- +Molecular assays +$ +19,037 +$ +21,907 +$ +26,283 +Non-molecular assays +108,723 +99,225 +110,399 +Total Diagnostics +$ +127,760 +$ +121,132 +$ +136,682 +Life Science- +Molecular reagents +$ +130,537 +$ +78,431 +$ +23,261 +Immunological reagents +59,599 +54,104 +41,071 +Total Life Science +$ +190,136 +$ +132,535 +$ +64,332 +Net Revenues by Disease State (Diagnostics only) +Year Ended September 30, +2021 +2020 +2019 +Diagnostics- +Gastrointestinal assays +$ +68,890 +$ +55,040 +$ +68,982 +Respiratory illness assays +17,608 +26,694 +26,622 +Blood chemistry assays +15,398 +17,534 +18,639 +Other +25,864 +21,864 +22,439 +Total Diagnostics +$ +127,760 +$ +121,132 +$ +136,682 +Royalty Income +Royalty income received from a third party related to sales of +H. pylori +products, totaled approximately $ 6,330 +, $ 3,540 +and +$ 3,440 for the years ended September 30, 2021 +, 2020 +and +2019 +, respectively. Such revenue is included as part of Non-molecular assays and Other within the Revenue by Product Platform/Type and Revenue by Disease State tables, respectively, above. +- 5 +6 +- +Table of Contents +Reagent Rental Arrangements +Revenue allocated to the lease elements of Reagent Rental arrangements totaled approximately $ 3,710 +, $ 4,600 +and +$ 4,150 for the years ended September 30, 2021 +, 2020 +and +2019 +, respectively. Such revenue is included as part of net revenues in our Consolidated Statements of Operations. +(3) +Fair Value Measurements +To limit exposure to volatility in the LIBOR interest rate, the Company has entered into interest rate swap agreements, which effectively convert the variable interest rate on $ 50,000 of the outstanding revolving credit facility discussed in Note 10 to a fixed rate. The fair values of the interest rate swap agreements were determined by reference to a third-party valuation and is considered a Level 2 input within the fair value hierarchy of valuation techniques. +As indicated in Note 4, we acquired the BreathTek business and Exalenz Bioscience Ltd. (“Exalenz”) in fiscal 2021 and 2020, respectively. In the BreathTek acquisition, the fair values of inventories acquired were valued using Level 2 inputs, which included data points that were observable, such as established values of comparable assets and historical sales information +(market approach). Identifiable +intangible assets, specifically the acquired customer relationships, +were +valued using Level 3 inputs, which are unobservable by nature, and included internal estimates of future cash flows and attrition rates (income approach). Significant increases (decreases) in any of those unobservable inputs, as of the date of the acquisition, in isolation would result in a significantly lower (higher) fair value measurement +. +In the Exalenz acquisition, the fair values of the acquired accounts receivable, inventories, property plant and equipment, and other current assets, and the fair values of the assumed accounts payable and accrued expenses, were valued using Level 2 inputs, which included data points that were observable, such as appraisals or established values of comparable assets (market approach). Identifiable intangible assets and contingent consideration were valued using Level 3 inputs, which are unobservable by nature, +a +nd included internal estimates of future cash flows (income approach). Significant increases (decreases) in any of those unobservable inputs, as of the date of the acquisition, in isolation would result in a significantly lower (higher) fair value measurement. Management engaged a third-party valuation firm to assist in the determination of acquisition fair values, and specifically those considered Level 3 measurements. Management ultimately maintained oversight over the third-party valuation firm to ensure that the transaction-specific assumptions were appropriate for the Company. +In connection with the acquisition of the business of GenePOC, Inc. (“GenePOC”) in fiscal 2019 and subsequent amendments to modify certain terms of the agreement related to contingent consideration achievement levels and milestone dates, the Company was required to make contingent consideration payments of up to $ 64,000 (originally $ 70,000 at the acquisition date), comprised of up to $ 14,000 for achievement of product development milestones (originally $ 20,000 at the acquisition date) and up to $ 50,000 for achievement of certain financial targets. The fair value for the contingent consideration recognized upon the acquisition as part of the purchase price allocation was $ 27,202 . Giving effect to subsequent agreements to modify certain terms of the agreement related to contingent consideration achievement levels and milestone dates, the fair value of the product development milestone payments were estimated by discounting the probability-weighted contingent payments to present value and presented on the Consolidated Balance Sheets based on the Company’s anticipated date of payment at each reporting period. Assumptions used in the calculations included probability of success, duration of the earn-out and discount rate, with such calculations being updated for the effect of the previously noted amendments to the contingent consideration achievement levels and milestone dates. The fair value of the financial performance target payments was determined using a Monte Carlo simulation-based model. Assumptions used in these calculations included expected net revenues, probability of certain developments, expected expenses and discount rate. In August 2021, the Company paid $ 20,000 to settle the contingent consideration obligation, resulting in a $ 909 net gain for the year ended September 30, 2021. +- 57 - +Table of Contents +The following table provides information by level for financial assets and liabilities that are measured at fair value on a recurring basis: +Fair Value Measurements Using +Inputs Considered as +Carrying +Value +Level 1 +Level 2 +Level 3 +Interest rate swap agreements - +As of September 30, 2021 +$ +( 203 +) +$ +— +$ +( 203 +) +$ +— +As of September 30, 2020 +$ +( 713 +) +$ +— +$ +( 713 +) +$ +— +Contingent consideration - +As of September 30, 2021 +$ +— +$ +— +$ +— +$ +— +As of September 30, 2020 +$ +( 20,909 +) +$ +— +$ +— +$ +( 20,909 +) +Supplemental Cash Flow Information (Non-Cash Acquisition Consideration) +In arriving at the $ 20,000 settlement payment, the acquisition consideration obligation related to acquisition of the GenePOC business decreased $ 909 and $ 6,293 during the years ended September 30, 2021 and 2020, respectively, due in large part to amendment of certain terms of the original contingent consideration achievement levels and milestone dates, as well as the settlement in August 2021. +(4) +Business Combinations +Acquisition of BreathTek Business +On July 31, 2021 (“the BreathTek acquisition date”), we acquired the BreathTek business, a urea breath t +e +st for the detection of +H. pylori +, from Otsuka America Pharmaceutical, Inc. Cash consideration totaled $ 19,585 , subject to a $ 1,000 holdback, which is recorded in acquisition consideration on the Consolidated Balance Sheets, to secure the selling party’s performance of certain post-closing obligations that is payable 15 months following the BreathTek acquisition date. As part of the acquisition, we primarily acquired BreathTek inventories and assumed the customer relationships to supply the BreathTek product in North America. The acquired inventories and customer relationships were valued on a preliminary basis at $ 9,855 and $ 9,730 , respectively, with the useful life of the customer relationships estimated at five years . The Company’s fiscal 2021 consolidated results include $ 3,840 of net revenues from sales of BreathTek products, which contributed approximately $ 1,000 of net earnings. These results, which are reported as part of the Diagnostics segment, include amortization expense related to the customer relationships recorded in the purchase price allocation totaling $ 324 for the year ended September 30, 2021. +Unaudited Pro Forma Information – BreathTek +The following table provides the unaudited consolidated pro forma results for the periods presented as if the BreathTek business had been acquired as of the beginning of fiscal 2020: +Year Ended September 30, +2021 +2020 +Net revenues +$ +337,118 +$ +279,573 +Net earnings +77,270 +53,305 +Acquisition of Exalenz +On April 30, 2020 (“the Exalenz acquisition date”), we acquired 100 % of the outstanding common shares and voting interest of Exalenz, a Modi’in, Israel based provider of the BreathID Breath Test Systems (“BreathID”), a breath test platform for the detection of +Helicobacter pylori. +Cash consideration totaled 168.6 million New Israeli Shekels (“NIS”), which equated to $ 48,237 at the date of closing. Including debt assumed and repaid shortly after closing, the total consideration transferred was $ 56,305 . To finance the acquisition, the Company utilized cash and cash equivalents on hand and proceeds drawn from our revolving credit facility (see Note 10). +- 58 - +Table of Contents +In anticipation of the acquisition, we executed forward currency contracts to acquire the NIS required for the acquisition. As a result, the net cash outlay for the transaction prior to the repayment of debt was $ 47,392 . The settlement of the currency contracts resulted in an $ 845 gain, which is reflected within other income (expense) in the Consolidated Statement of Operations for the year ended September 30, 2020. +As a result of total consideration exceeding the fair value of the net assets acquired, goodwill in the amount of $ 24,459 was recorded in connection with this acquisition, none of which will be deductible for U.S. tax purposes. The goodwill results largely from our ability to market and sell the BreathID system through our established customer base and distribution channels. The Consolidated Statement of Operations for the year ended September 30, 2020 +, +included $ 3,890 of acquisition-related costs related to the Exalenz acquisition, which are reflected in operating expenses. +The Company’s consolidated results include the following from Exalenz: +Year Ended September 30, +2021 +2020 +Net revenues +$ +14,905 +$ +4,206 +Net loss +( 3,381 +) +( 1,911 +) +These results, which are reported as part of the Diagnostics segment, include amortization expense related to specific identifiable assets recorded in the purchase price allocation, including a non-compete agreement, trade name, technology and customer relationships, totaling $ 2,960 and $ 1,120 for the years ended September 30, 2021 and 2020, respectively. +The following table summarizes the final (as of April 30, +2021 +) fair values of the identifiable assets acquired and liabilities assumed in the acquisition of Exalenz (as of the Exalenz acquisition date): +April 30, 2020 +Fair value of assets acquired - +Cash +$ +5,006 +Accounts receivable +637 +Inventories +4,026 +Other current assets +2,676 +Property, plant and equipment +528 +Goodwill +24,459 +Other intangible assets (estimated useful life): +Non-compete agreement ( 5 years) +110 +Trade name ( 10 years) +3,860 +Technology ( 15 years) +6,120 +Customer relationships ( 10 years) +20,640 +Right-of-use assets +1,311 +Deferred tax assets, net +7,119 +76,492 +Fair value of liabilities assumed - +Accounts payable and accrued expenses (including current portion of lease and government grant obligations) +8,008 +Long-term lease obligations +1,096 +Long-term government grant obligations +10,792 +Other non-current liabilities +291 +20,187 +Total consideration paid (including $ 8,068 to pay off long-term debt) +$ +56,305 +- 59 - +Table of Contents +Unaudited Pro Forma Information – Exalenz +The following table provides the unaudited consolidated pro forma results for the periods presented as if Exalenz had been acquired as of the beginning of fiscal 2019. Pro forma results do not include the effect of any synergies anticipated to be achieved from the acquisition, and accordingly, are not necessarily indicative of the results that would have occurred if the acquisition had occurred on the date indicated or that may result in the future. +Year Ended September 30, +2020 +2019 +Net revenues +$ +261,131 +$ +214,613 +Net earnings +45,843 +19,089 +These pro forma amounts have been calculated by including the results of Exalenz and adjusting the combined results to give effect to the following, as if the acquisitions had been consummated on October 1, 2018, together with the consequential tax effects thereon: +Year Ended September 30, +2020 +2019 +Adjustments to Net Revenues +Exalenz pre-acquisition revenues +$ +7,464 +$ +13,599 +Adjustments to Net Earnings +Exalenz pre-acquisition net losses +$ +( 6,423 +) +$ +( 4,006 +) +Pro forma adjustments: +Meridian acquisition-related costs +3,890 +— +Exalenz transaction-related costs +4,550 +— +Gain on Exalenz purchase price currency contracts +( 845 +) +— +Remove net impact of non-continuing activities +( 305 +) +1,441 +Incremental depreciation and amortization +( 1,680 +) +( 3,027 +) +Incremental interest costs, net +( 183 +) +( 728 +) +Tax effects of pro forma adjustments and recognizing benefit on resulting Exalenz losses +653 +1,027 +Total Adjustments to Net Earnings +$ +( 343 +) +$ +( 5,293 +) +(5) +Lead Testing Matters +On September 1, 2021, the Company’s wholly owned subsidiary Magellan announced the expansion of a Cl +a +ss I voluntary recall of its LeadCare test kits for the detection of lead in blood, which it had initiated in May 2021. Customers generally run controls when they receive a new lot of product and have reported to us that the control results are outside of specified ranges. As a result of the identified issue, impacted test kit lots could potentially underestimate blood lead levels when processing patient blood samples. Although we have not determined the root cause at this time, we currently believe that the issue relates to the plastic containers used for the treatment reagent, which are supplied by a firm in China. The Company is working closely with the FDA in its execution of the recall activities, which include notifications to customers and distributors, and providing instructions for the return of impacted test kits. Although evaluation of the recall and the related notification process is ongoing, approximately $ 5,100 has been estimated and accrued as of September 30, 2021, to cover the currently estimated costs of the recall +. +In total, approximately +$ 5,600 of recall-related expense +has been +included within the Consolidated Statement of Operations for the year ended September 30, 2021. Anticipated recall-related costs, which primarily include product replacement and/or refund costs, mailing/shipping costs, attorneys’ fees, and other miscellaneous costs are estimated based upon the most recent information available. Information utilized in the accrual estimation process includes observable inputs such as customer on-hand inventory data, product sales data, average sales price, and product inventory turns, among other things. Available information is subject to change as the recall period extends, and such changes will be recorded in the period known. +- 60 - +Table of Contents +On April 17, 2018 , the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlines documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies +and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas calling for witnesses to testify before a federal grand jury related to this matter. The March 2021 subpoena was issued to a former employee of Magellan, and the April subpoena was issued to a current employee of Magellan. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. The Company cannot predict when the investigation will be resolved, the outcome of the investigation, or its potential impact on the Company. Approximately $ +2,803 +, $ +2,035 +and $ +1,585 +of expense for attorneys’ fees related to this matter is included within the Consolidated Statements of Operations for the years ended September 30, 2021, 2020 and 2019, respectively. +Magellan submitted 510(k) applications in December 2018, seeking to reinstate venous blood sample-types for its LeadCare II, LeadCare Plus and LeadCare Ultra testing systems. In the second fiscal quarter of 2019 the FDA informed Magellan that each of these 510(k) applications had been put on Additional Information hold. On July 15, 2019, we provided responses to the FDA’s requests for Additional Information. These 510(k) applications have since expired and are no longer under FDA review. Further, while Magellan’s LeadCare testing systems remain cleared for marketing by the FDA and permitted for use with capillary blood samples, the FDA advised that it has commissioned a third-party study of the Company’s LeadCare testing systems using both venous and capillary blood samples. According to the FDA, the results of the field study will be used in conjunction with other information to determine whether further action by the FDA or the Centers for Disease Control and Prevention (“CDC”) is necessary to protect the public health. The Company intends to fully cooperate with the FDA or CDC on any follow-up based on the third-party study. +During October 2019, the FDA performed a follow-up inspection of Magellan’s manufacturing facility. The FDA issued five Form FDA 483 observations. On March 18, 2020, we participated in a regulatory meeting with the FDA at the FDA’s request to further discuss the Form FDA 483 observations and our remediation efforts. Since the inspection, we have submitted a number of written responses to the FDA regarding the five Form FDA 483 observations issued in the October 2019 inspection, and have worked diligently to execute a remediation plan. During October 2020, the FDA issued Establishment Inspection Reports which closed out the inspections from June 2017 and October 2019 under 21 C.F.R.20.64(d)(3). +During June 2021, the FDA performed an inspection of Magellan’s manufacturing facility. As a result of this inspection, the FDA issued one Form 483 observation. On August 3, 2021, FDA sent Magellan a close-out letter for the Warning Letter that FDA issued to Magellan on October 23, 2017. FDA’s close-out letter notified Magellan that FDA has completed an evaluation of Magellan’s corrective actions in response to FDA’s Warning Letter, and based on FDA’s evaluation, Magellan has addressed the issues identified in the Warning Letter. FDA’s close-out letter also stated that future FDA inspections of Magellan and regulatory activities will further assess the adequacy and sustainability of Magellan’s corrections. +(6) +Cash and Cash Equivalents +Cash and cash equivalents are comprised of the following: +As of September 30, +2021 +2020 +Institutional money market funds +$ +1,020 +$ +1,017 +Cash on hand, unrestricted +48,751 +52,497 +Total +$ +49,771 +$ +53,514 +- 61 - +Table of Contents +Cash equivalents, institutional money market funds, are classified within Level 1 of the fair value hierarchy. Financial instruments classified as Level 1 are based on quoted market prices in active markets. The Company does not adjust the quoted market price for such financial instruments. +(7) +Inventories +Inventories are comprised of the following: +As of September 30, +2021 +2020 +Raw materials +$ +14,843 +$ +11,966 +Work-in-process +25,072 +19,477 +Finished goods - instruments +2,260 +1,594 +Finished goods - kits and reagents +34,667 +28,227 +Total +$ +76,842 +$ +61,264 +(8) +Goodwill and Other Intangible Assets, Net +During fiscal 2021, goodwill increased $ 482 , reflecting: (i) a $ 56 increase from the currency translation adjustment on goodwill in the Diagnostics segment; (ii) a $ 433 increase from the currency translation adjustment on goodwill in the Life Science segment; and (iii) a $ 7 decrease related to Exalenz, reflecting additional measurement period adjustments (see Note 4). +A summary of Meridian’s intangible assets subject to amortization is as follows. +2021 +2020 +As of September 30, +Gross +Carrying +Value +Accum. +Amort. +Gross +Carrying +Value +Accum. +Amort. +Manufacturing technologies, core products and cell lines +$ +62,416 +$ +22,633 +$ +62,363 +$ +18,750 +Tradenames, licenses and patents +18,489 +9,492 +18,425 +7,801 +Customer lists, customer relationships and supply agreements +54,941 +19,649 +45,071 +16,210 +Non-compete agreements +110 +31 +110 +11 +$ +135,956 +$ +51,805 +$ +125,969 +$ +42,772 +The aggregate amortization expense for these intangible assets for the years ended September 30, 2021, 2020 and 2019 was $ 8,776 , $ 7,744 and $ 4,531 , respectively. The estimated aggregate amortization expense for these intangible assets for each of the five succeeding fiscal years is as follows: fiscal 2022 - $ 9,940 , fiscal 2023 - $ 9,925 , fiscal 2024 - $ 9,920 , fiscal 2025 - $ 9,915 and fiscal 2026 - $ 8,915 . +(9) +Leasing Arrangements +The Company is party to several operating leases, the majority of which are related to office, warehouse and manufacturing space. The related operating lease assets and obligations are reflected within right-of-use assets, net, current operating lease obligations and long-term operating lease obligations on the Consolidated Balance Sheets. Lease expense for these leases is recognized on a straight-line basis over the lease term, with variable lease payments recognized in the period those payments are incurred. +- 62 - +Table of Contents +The lease costs for these operating leases reflected in our Consolidated Statements of Operations, as well as the right-of-use assets, net obtained during these periods in exchange for operating lease liabilities, are as follows: +Year Ended September 30, +2021 +2020 +Lease costs within cost of sales +$ +795 +$ +597 +Lease costs within operating expenses +1,542 +1,286 +Right-of-use assets, net obtained in exchange for operating lease liabilities +1,073 +1,600 +The amounts charged to expense under operating leases in fiscal 2019 tot +a +led $2,372. In addition, the Company periodically enters into other short-term operating leases, generally with an initial term of twelve months or less. These leases are not recorded on the Consolidated Balance Sheet +s +and the related lease expense is immaterial for fiscal 2021 and 2020. +The Company often has options to renew lease terms, with the exercise of lease renewal options generally at the Company’s sole discretion. In addition, certain lease arrangements may be terminated prior to their original expiration date at our discretion. We evaluate renewal and termination options at the lease commencement date to determine if we are reasonably certain to exercise the option on the basis of economic factors. The discount rate implicit within our leases is generally not determinable and, therefore, the Company uses its incremental borrowing rate as the basis for its discount rate. The weighted average remaining lease term for our operating leases and the weighted average discount rate used to measure our operating leases were as follows: +As of September 30, +2021 +2020 +Weighted average remaining lease term +3.6 yrs. +4.2 yrs. +Average discount rate +3.2 +% +3.7 +% +Maturities of lease liabilities by fiscal year for the Company’s operating lease liabilities were as follows as of September 30, 2021: +2022 +$ +2,194 +2023 +1,558 +2024 +1,178 +2025 +918 +2026 +326 +Thereafter +65 +Total lease payments +6,239 +Less amount of lease payment representing interest +( 317 +) +Total present value of lease payments +$ +5,922 +Supplemental Cash Flow Information (Cash Paid for Amounts Included in Measurement of Lease Liabilities) +Year Ended September 30, +2021 +2020 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases +$ +2,228 +$ +1,693 +- 63 - +Table of Contents +(10) +Bank Credit Arrangements +The Company maintains a revolving credit facility with a commercial bank in an aggregate principal amount not to exceed $ 160,000 , which expires in May 2024 +(see Note 17 for discussion of +the +post Consolidated Balance Sheet date amendment to the revolving credit facility). +Outstanding principal amounts bear interest at a fluctuating rate tied to, at the Company’s option, either the federal funds rate or LIBOR, resulting in an effective interest rate of 2.51 % and 3.30 % on the revolving credit facility during fiscal 2021 and 2020, respectively. In light of the interest being determined on a variable rate basis, the fair value of the borrowings under the credit facility at both September 30, 2021 and 2020 approximates the current carrying value reflected in the Consolidated Balance Sheets of $ 60,000 and $ 68,824 , +respectively, which is consistent with a level 2 +fair v +a +lue measurement. +The revolving credit facility is collateralized by the business assets of the Company’s U.S. subsidiaries and requires compliance with financial covenants that limit the amount of debt obligations and require a minimum level of coverage of fixed charges, as defined in the revolving credit facility agreement. As of September 30, 2021, the Company was in compliance with all covenants. +Supplemental Cash Flow Information (Interest Paid) +Cash paid for interest totaled $ 1,348 , $ 2,690 and $ 1,405 in fiscal 2021, 2021 and 2019, respectively. +(11) +Income Taxes +(a) +Earnings before income taxes, and the related income tax provision were as follows: +Year Ended September 30, +2021 +2020 +2019 +Domestic +$ +11,354 +$ +9,068 +$ +23,954 +Foreign +79,097 +50,225 +7,603 +Total earnings before income taxes +$ +90,451 +$ +59,293 +$ +31,557 +Provision +(benefit) +for income taxes - +Federal - +Current +$ +4,431 +$ +1,173 +$ +5,001 +Deferred +( 2,595 +) +744 +( 477 +) +State and local +1,163 +1,170 +834 +Foreign - +Current +16,305 +10,194 +1,915 +Deferred +( 260 +) +( 174 +) +( 98 +) +Total income tax provision +$ +19,044 +$ +13,107 +$ +7,175 +- 64 - +Table of Contents +(b) +The following is a reconciliation between the statutory U.S. income tax rate and the effective rate derived by dividing the income tax provision by earnings before income taxes: +Year Ended September 30, +2021 +2020 +2019 +Computed income taxes at statutory rate +$ +18,995 +21.0 +% +$ +12,452 +21.0 +% +$ +6,627 +21.0 +% +Increase (decrease) in taxes resulting from - +State and local income taxes +1,204 +1.3 +773 +1.3 +577 +1.8 +Foreign-Derived Intangible Income tax +( 563 +) +( 0.6 +) +( 136 +) +( 0.2 +) +( 294 +) +( 0.9 +) +Global Intangible Low Taxed Income +(“GILTI”) +tax +8,061 +8.9 +4,970 +8.4 +1,119 +3.5 +Foreign tax credit +( 7,802 +) +( 8.6 +) +( 4,767 +) +( 8.0 +) +( 990 +) +( 3.1 +) +Foreign tax rate differences +( 869 +) +( 1.0 +) +( 534 +) +( 0.9 +) +46 +0.1 +Transaction costs +— +— +548 +0.9 +— +— +Uncertain tax position activity +205 +0.2 +62 +0.1 +126 +0.4 +Valuation allowance +729 +0.8 +229 +0.3 +364 +1.2 +Stock-based compensation +( 498 +) +( 0.5 +) +41 +0.1 +( 33 +) +( 0.1 +) +Other, net +( 418 +) +( 0.4 +) +( 531 +) +( 0.9 +) +( 367 +) +( 1.2 +) +$ +19,044 +21.1 +% +$ +13,107 +22.1 +% +$ +7,175 +22.7 +% +The Company’s GILTI and foreign tax credit details were as follows: +Year Ended September 30, +2021 +2020 +2019 +U.S. GILTI inclusion +$ +38,384 +$ +23,666 +$ +5,328 +Resulting permanent tax expense +8,061 +4,970 +1,119 +Offsetting foreign tax credit +( 7,802 +) +( 4,767 +) +( 990 +) +(c) +The components of net deferred taxes were as follows: +As of September 30, +2021 +2020 +Deferred tax assets - +Valuation reserves and non-deductible expenses +$ +4,939 +$ +4,848 +Stock compensation expense not deductible +2,276 +1,804 +Net operating loss and tax credit carryforwards +12,711 +10,757 +Basis difference in equity-method investee +302 +302 +Inventories basis differences +692 +382 +Other +— +207 +Subtotal +20,920 +18,300 +Less valuation allowance +( 1,624 +) +( 895 +) +Deferred tax assets +19,296 +17,405 +Deferred tax liabilities - +Property, plant and equipment basis differences and depreciation +( 4,778 +) +( 4,269 +) +Intangible asset basis differences and amortization +( 6,495 +) +( 9,293 +) +Other +( 347 +) +— +Deferred tax liabilities +( 11,620 +) +( 13,562 +) +Net deferred tax assets +$ +7,676 +$ +3,843 +- 65 - +Table of Contents +For income tax purposes, we have recorded deferred tax assets related to operating loss and tax credit carryforwards of $ 179 in the U.S. and $ 12,532 in foreign jurisdictions as of September 30, 2021, reduced by valuation reserves totaling $ 1,322 . At September 30, 2020, such deferred tax assets totaled $ 205 and $ 10,552 , respectively, +reduced by valuation reserves totaling $ 593 . The operating loss carryforwards in foreign jurisdictions, the majority of which relate to Israel, have no expiration date. The operating loss carryforwards in the U.S. expire in 2023 at the federal level, and in 2036 at the state level. The aggregate amount of federal, state and foreign operating loss carryforwards separately totaled $ 118 , $ 2,400 and $ 88,442 , respectively, at September 30, 2021. The use of the federal and state losses is limited by the change of ownership provisions of the Internal Revenue Code. +The Company has recognized a deferred tax liability of $ 865 and $ 185 at September 30, 2021 and 2020, respectively, to reflect the corporate and withholding tax impact of a presumed repatriation of foreign earnings. +The realization of deferred tax assets is dependent upon the generation of future taxable incom +e +in the applicable jurisdictions. We have considered the levels of currently anticipated pre-tax income in U.S. and foreign jurisdictions in assessing the required level of the deferred tax asset valuation allowance including the characterization of the income as ordinary or capital. Taking into consideration historical and current operating results, and other factors, we believe that it is more likely than not that the net deferred tax asset of $ 19,296 will be realized. The amount of the net deferred tax asset considered realizable, however, could be reduced in future years if estimates of future taxable income are reduced. +We utilize a comprehensive model for the recognition, measurement, presentation and disclosure of uncertain tax positions, assuming full knowledge of all relevant facts by the applicable tax authorities. The total amount of unrecognized tax benefits at September 30, 2021 and 2020 related to such positions was $ 700 and $ 568 , respectively, of which $ 627 at September 30, 2021 would favorably impact the effective tax rate if recognized. We generally recognize interest and penalties related to uncertain tax positions as a component of our income tax provision. During fiscal 2021 and 2020, such penalties and interest totaled approximately $ 31 and $ 20 , respectively. We had approximately $ 170 accrued for the payment of interest and penalties at September 30, 2021, compared to $ 138 accrued at September 30, 2020. The amount of our liability for uncertain tax positions expected to be paid or settled in the next 12 months is uncertain. +A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: +Year Ended September 30, +2021 +2020 +2019 +Unrecognized income tax benefits at beginning of year +$ +568 +$ +509 +$ +388 +Additions for tax positions of prior years +34 +— +83 +Reductions for tax positions of prior years +— +— +( 38 +) +Additions for tax positions of current year +138 +104 +138 +Tax examination and other settlements +( 40 +) +( 45 +) +( 62 +) +Unrecognized income tax benefits at end of year +$ +700 +$ +568 +$ +509 +We are subject to examination by the tax authorities in the U.S. (both federal and state) and the countries of Australia, Belgium, Canada, China, England, France, Germany, Holland, Israel and Italy. In the U.S., tax years subsequent to fiscal 2017 remain open . In countries outside the U.S., open tax years generally range from fiscal 2016 and forward . However, in Australia and Belgium, the utilization of local net operating loss carryforwards extends the statute of limitations for examination well into the foreseeable future. To the extent that adjustments result from the completion of these examinations or the lapsing of statutes of limitation, they will affect tax liabilities in the period known. We believe that the results of any tax authority examinations would not have a significant adverse impact on our consolidated financial condition or results of operations. +Supplemental Cash Flow Information (Income Taxes Paid) +Cash paid for income taxes totaled $ 27,466 , $ 9,816 and $ 7,840 in fiscal 2021, 2020 and 2019, respectively. +- 66 - +Table of Contents +(12) +Employee Benefits +(a) +Savings and Investment Plan +- +We have a profit sharing and retirement savings plan covering substantially all full-time U.S. employees. Profit sharing contributions to the plan, which are discretionary, are approved by the board of directors. The plan permits participants to contribute to the plan through salary reduction. Under terms of the plan, we match 100 % of an employee’s contributions, up to a maximum match of 4 % of eligible compensation. Our discretionary and matching contributions to the plan, which +are +recorded primarily within operating expenses, amounted to approximately $ 2,869 , $ 2,434 and $ 1,979 , for the years ended September 30, 2021, 2020 and 2019, respectively. +(b) +Stock-Based Compensation Plans +- +During fiscal 2021, the Company had two active stock-based compensation plans, the 2012 Stock Incentive Plan, which became effective January 25, 2012 (the “2012 Plan”) and the 2021 Omnibus Award Plan, which became effective January 27, 2021 (the “2021 Plan”). +The 2021 Plan is authorized to grant new shares for options, restricted shares or restricted share units for up to 2,839 shares, including 1,839 non-granted shares from the 2012 Plan permitted to be carried forward and added to the 2021 Plan authorized limit. As of September 30, 2021, 71 shares have been granted under the 2021 Plan, thereby resulting in a remaining authorized limit of 2,768 shares. Options may be granted at exercise prices not less than 100 % of the closing market value of the underlying common shares on the date of grant and have maximum terms up to ten years . Vesting schedules for options, restricted shares and restricted share units are established at the time of grant and may be set based on future service periods, achievement of performance targets, or a combination thereof. All options contain provisions restricting their transferability and limiting their exercise in the event of termination of employment, or the disability or death of the optionee. We recognize compensation expense for all share-based payments made to employees, based upon the fair value of the share-based payment on the date of the grant. +During fiscal years 2019 through 2021, we granted, in the aggregate for the three-year period, approximately 823 restricted share units (with weighted-average grant date fair values of $ 18.66 per share in fiscal 2019, $ 10.13 per share in fiscal 2020 and $ 18.81 per share in fiscal 2021) to certain employees, including CEO, Jack Kenny, as separately detailed below. The units granted in fiscal 2021, 2020 and 2019 were generally time-vested restricted share units vesting in total on the third anniversary of the grant date. +During fiscal 2020, in connection with Mr. Kenny’s Amended and Restated Employment Agreement, effective October 1, 2019, we granted to Mr. Kenny: (i) options to purchase approximately 198 shares of common stock of the Company (with a grant date fair value of $ 3.38 per share) vesting on a pro rata basis over the three years ending October 1, 2022 ; and (ii) approximately 100 restricted share units (with a grant date fair value of $ 10.10 per share) vesting 100 % on the October 1, 2022, which are included within the restricted share units noted above. +Giving effect to these grants, cancellations and certain other activities for restricted shares and restricted share units throughout the years, including conversions to common shares, forfeitures, and new hire and employee promotion grants, approximately 682 restricted share units remain outstanding as of September 30, 2021, with a weighted-average grant date fair value of $ 14.73 per share, a weighted-average remaining vesting period of 1.12 years and an aggregate intrinsic value of $ 13,121 . The weighted-average grant date fair value of the approximate 79 restricted share units that vested during fiscal 2021 was $ 15.61 per share. +The amount of stock-based compensation expense was $ 4,156 , $ 3,802 and $ 3,251 for the years ended September 30, 2021, 2020 and 2019, respectively. The fiscal 2021 expense is comprised of $ 1,080 related to stock options and $ 3,076 related to restricted share units; the fiscal 2020 expense is comprised of $ 1,006 related to stock options and $ 2,796 related to restricted share units ; and the fiscal 2019 expense is comprised of $ 542 related to stock options and $ 2,709 related to restricted share units. The total income tax benefit recognized in the Consolidated Statements of Operations for these stock-based compensation arrangements was $ 1,516 , $ 898 and $ 572 , for the years ended September 30, 2021, 2020 and 2019, respectively. As of September 30, 2021, we expect future stock compensation expense for unvested options and unvested restricted share units to total $ 902 and $ 3,438 , respectively, which will be recognized during fiscal years 2022 through 2024 . +- 67 - +Table of Contents +We recognize stock-based compensation expense only for the portion of shares that we expect to vest. As such, we apply estimated forfeiture rates to our stock-based compensation expense calculations. These rates have been derived using historical forfeiture data, stratified by several employee groups, and range from 0 % to 16 % in each of the years ended September 30, 2021, 2020 and 2019. During the years ended September 30, 2021, 2020 and 2019, we recorded $ 183 , $ 148 and $ 127 , respectively, in stock-based compensation expense to adjust estimated forfeiture rates to actual. +We have elected to use the Black-Scholes option pricing model to determine grant-date fair value for stock options, with the following assumptions: (i) expected share price volatility based on the average of Meridian’s historic +a +l volatility over the options’ expected lives and implied volatility based on the value of tradable call options; (ii) expected life of options based on contractual lives, employees’ historical exercise behavior and employees’ historical post-vesting employment termination behavior; (iii) risk-free interest rates based on treasury rates that correspond to the expected lives of the options; and (iv) dividend yield based on the expected yield on underlying Meridian common stock. +A summary of these key assumptions are as follows: +Year ended September 30, +2021 +2020 +2019 +Share price volatility +53 %- 59 % +34 +% +29 +% +Life of option +4.00 - 7.47 yrs. +6.51 yrs +. +6.51 yrs +. +Risk-free interest rates +0.26 % +- +0.79 % +1.60 +% +2.99 +% +Dividend yield +0 +% +0 +% +3.3 +% +A summary of the status of our stock option plans as of September 30, 2021, and changes during the year ended September 30, 2021, is presented in the table and narrative below: +Options +Wtd Avg +Exercise +Price +Wtd Avg +Remaining +Life (Yrs) +Aggregate +Intrinsic +Value +Outstanding beginning of period +1,103 +$ +14.67 +Grants +167 +19.28 +Exercises +( 219 +) +14.48 +Forfeitures +( 19 +) +11.46 +Cancellations +( 31 +) +21.85 +Outstanding end of period +1,001 +$ +15.31 +6.55 +$ +4,299 +Exercisable end of period +598 +$ +15.90 +5.44 +$ +2,276 +A summary of the status of our nonvested options as of September 30, 2021, and changes during the year ended September 30, 2021, is presented below: +Options +Weighted- +Average +Grant Date +Fair Value +Nonvested beginning of period +429 +$ +3.36 +Granted +167 +9.18 +Vested +( 174 +) +3.59 +Forfeitures +( 19 +) +2.83 +Nonvested end of period +403 +$ +5.70 +- 68 - +Table of Contents +For the years ended September 30, 2021, 2020 and 2019: (i) the weighted average grant-date fair value of options granted was $ 9.18 , $ 3.54 and $ 3.61 , respectively; (ii) the total intrinsic value of options exercised was $ 2,890 , $ 1,585 and $ 62 , respectively; and (iii) the total grant-date fair value of options that vested was $ 621 , $ 528 and $ 735 , respectively. +Cash received from options exercised was $ 3,052 , $ 3,559 and $ 443 for the years ended September 30, 2021, 2020 and 2019, respectively. +(13) +Contingent Obligations and Non-Current Liabilities +In connection with the acquisition of Exalenz (see Note 4), the Company assumed several Israeli government grant obligations. The repayment of the grants, along with interest incurred at varying stated fixed rates based on LIBOR at the time each grant was received (ranging from 0.58 % to 6.60 %), is not dictated by an established repayment schedule. Rather, the grants and related interest are required to be repaid using 3 % of the net revenues generated from the sales of BreathID products, with repayment contingent upon the level and timing of such revenues. In addition, the grants have no collateral or financial covenant provisions generally associated with traditional borrowing instruments. Following the repayment of a substantial portion (approximately $ 5,300 ) of the higher rate grant obligations during fiscal 2021, these obligation amounts total $ 5,814 and $ 11,124 as of September 30, 2021 and 2020, with the grant obligations remaining at September 30, 2021, bearing interest at rates ranging from 0.58 % to 2.02 %. +The grant obligations are reflected in the Consolidated Balance Sheets as follows: +Year Ended September 30, +2021 +2020 +Current liabilities +$ +638 +$ +600 +Non-current liabilities +5,176 +10,524 +Additionally, the Company has provided certain post-employment benefits to its former Chief Executive Officer, and these obligations total $ 1,676 and $ 1,840 at September 30, 2021 and 2020, respectively. In addition, the Company is required by the governments of certain foreign countries in which we operate to maintain a level of accruals for potential future severance indemnity. These accruals total $ 754 and $ 814 at September 30, 2021 and 2020, respectively. +(14) +National Institutes of Health Contracts +In December 2020, the Company entered into a sub-award grant contract with the University of Massachusetts Medical School as part of the National Institutes of Health Rapid Acceleration of Diagnostics (“RADx”) initiative to support the Company’s research and development of its diagnostic test for the SARS-CoV-2 antigen. The Company has received $ 1,000 under the grant contract for reimbursement of eligible research and development expenditures. These amounts are included within other income (expense) in the Consolidated Statement of Operations for the year ended September 30, 2021. +Effective February 1, 2021, the Company entered into a second grant contract under the RADx initiative, the purpose of which is to support the Company’s manufacturing production scale-up and expansion to meet the demand for COVID-19 testing. The contract is a twelve-month term service contract, with payment of up to $ 5,500 being made based on the Company achieving key milestones related to increasing its capacity to produce COVID-19 tests. As of September 30, 2021, $ 1,500 has been received related to this contract and is reflected as a reduction in the cost of equipment within construction in progress on the Consolidated Balance Sheet. +- 69 - +Table of Contents +(15) +Reportable Segments and Major Concentration Data +The Company’s reportable segments maintain separate financial information for which results of operations are evaluated on a regular basis by the Company’s chief operating decision maker in deciding how to allocate resources and in assessing performance. +The Company records the direct costs of business operations to the reportable segments, including allocations for certain corporate-wide costs such as treasury management, human resources and technology, among others. Corporate provides certain ex +e +cutive management and administrative services to each reportable segment. These services primarily include executive oversight by non-segment-specific executives, including the Board of Directors, along with certain other corporate-wide support functions such as insurance, legal and business development. The Company generally does not allocate these types of corporate expenses to the reportable segments. +Segment and Corporate information is as follows: +Diagnostics +Life Science +Corporate +(1) +Eliminations +(2) +Total +Fiscal 2021 +Net revenues - +Third-party +$ +127,760 +$ +190,136 +$ +— +$ +— +$ +317,896 +Inter-segment +351 +207 +— +( 558 +) +— +Operating (loss) income +( 8,140 +) +115,250 +( 14,164 +) +88 +93,034 +Depreciation and amortization +13,432 +1,854 +— +— +15,286 +Capital expenditures +15,827 +2,485 +— +— +18,312 +Goodwill +94,904 +19,764 +— +— +114,668 +Other intangible assets, net +84,149 +2 +— +— +84,151 +Total assets +339,208 +110,536 +— +( 22 +) +449,722 +Fiscal 2020 +Net revenues - +Third-party +$ +121,132 +$ +132,535 +$ +— +$ +— +$ +253,667 +Inter-segment +326 +261 +— +( 587 +) +— +Operating (loss) income +3,885 +68,826 +( 11,437 +) +50 +61,324 +Depreciation and amortization +11,451 +2,116 +— +— +13,567 +Capital expenditures +1,850 +1,449 +— +— +3,299 +Goodwill +94,855 +19,331 +— +— +114,186 +Other intangible assets, net +83,179 +18 +— +— +83,197 +Total assets +306,812 +98,483 +— +( 34 +) +405,261 +Fiscal 2019 +Net revenues - +Third-party +$ +136,682 +$ +64,332 +$ +— +$ +— +$ +201,014 +Inter-segment +462 +361 +— +( 823 +) +— +Operating (loss) income +25,390 +17,581 +( 10,373 +) +101 +32,699 +Depreciation and amortization +7,676 +2,288 +— +— +9,964 +Capital expenditures +2,049 +1,748 +— +— +3,797 +Goodwill +70,395 +18,846 +— +— +89,241 +Other intangible assets, net +59,807 +436 +— +— +60,243 +Total assets +255,169 +70,392 +— +( 83 +) +325,478 +(1) +Includes Restructuring and Selected Legal Costs of $ 2,803 , $ 2,080 and $ 2,596 for the years ended September 30, 2021, 2020 and 2019, respectively. +(2) +Eliminations consist of inter-segment transactions. +- 70 - +Table of Contents +A reconciliation of reportable segment operating income to consolidated earnings before income taxes is as follows: +Year Ended September 30, +2021 +2020 +2019 +Operating (loss) income: +Diagnostics segment +$ +( 8,140 +) +$ +3,885 +$ +25,390 +Life Science segment +115,250 +68,826 +17,581 +Eliminations +88 +50 +101 +Total reportable segment operating income +107,198 +72,761 +43,072 +Corporate operating expenses +( 14,164 +) +( 11,437 +) +( 10,373 +) +Interest income +— +142 +681 +Interest expense +( 1,878 +) +( 2,632 +) +( 1,945 +) +RADx initiative grant income +1,000 +— +— +Other, net +( 1,705 +) +459 +122 +Consolidated earnings before income taxes +$ +90,451 +$ +59,293 +$ +31,557 +Transactions between reportable segments are accounted for at established intercompany prices for internal and management purposes with all intercompany amounts eliminated in consolidation. +During +the years ended September 30, 2021 and 2020, products related to COVID-19 accounted for 59 % and 54 %, respectively, of Life Science segment net revenues +, +and 35 % +and +28 %, respectively, of consolidated net revenues. In addition, net revenues generated by the Company’s three major Diagnostics +segment +product families – gastrointestinal, respiratory illnesses and blood chemistry – accounted for 32 %, 39 % and 57 % of consolidated net revenues during the years ended September 30, 2021, 2020 and 2019, respectively. +While no individual Diagnostics or Life Science +segment +customers accounted for greater than 10 % of consolidated net revenues during the years ended September 30, 2021, 2020 and 2019, individual Diagnostics or Life Science segment customers, including their affiliates, comprising 10 % or more of reportable segment net revenues were as follows: +Year Ended September 30, +2021 +2020 +2019 +Diagnostics +Customer A +10 +% +12 +% +13 +% +Customer B +11 +% +13 +% +12 +% +Customer C +12 +% +7 +% +6 +% +Life Science +Customer D +6 +% +6 +% +18 +% +Customer E +3 +% +13 +% +7 +% +Customer F +13 +% +11 +% +2 +% +In addition, for the years ended September 30, 2021, 2020 and 2019, the Life Science segment’s ten largest customers, including their affiliates, accounted for approximately +44 +%, +48 +% and +42 +%, respectively, of Life Science segment net revenues, and +27 +%, +25 +% and +13 +%, respectively, of consolidated net revenues. +One Diagnostics segment customer (Customer B above) and one Life Science +segment +customer (Customer F above) accounted for approximately 12 % and 10 %, respectively, of consolidated accounts receivable as of September 30, 2021. As of September 30, 2020, only Customer F above accounted for greater than 10 % of consolidated accounts receivable, accounting for approximately 15 %. +- 71 - +Table of Contents +Net revenues generated by the Company outside of the U.S. and its territories totaled $ 173,475 , $ 121,596 and $ 74,193 for the years ended September 30, 2021, 2020 and 2019, respectively, with net revenues by country for the Diagnostics and Life Science segments as follows (net revenues are attributed to the geographic area based on the location to which the product is delivered): +Year Ended September 30, +2021 +2020 +2019 +U.S. and territories +$ +99,636 +$ +95,382 +$ +107,890 +Italy +12,240 +9,797 +10,911 +France +2,283 +2,238 +2,446 +United Kingdom +2,197 +2,312 +2,396 +Belgium +1,554 +1,440 +1,468 +Holland +1,279 +1,183 +1,413 +Finland +1,069 +275 +291 +Japan +551 +848 +1,572 +Other countries +6,951 +7,657 +8,295 +Total Diagnostics +$ +127,760 +$ +121,132 +$ +136,682 +Year Ended September 30, +2021 +2020 +2019 +U.S. and territories +$ +44,785 +$ +36,689 +$ +18,931 +Germany +18,460 +14,190 +12,663 +Finland +17,936 +2,518 +500 +China +13,559 +19,047 +8,464 +United Kingdom +13,097 +14,765 +4,709 +Spain +12,593 +7,242 +4,414 +France +10,733 +5,579 +2,200 +South Korea +9,242 +1,908 +1,134 +Australia +9,115 +5,957 +3,458 +Italy +7,516 +4,067 +1,357 +Turkey +7,281 +2,819 +290 +Japan +6,532 +3,707 +1,624 +India +5,558 +2,099 +143 +Indonesia +5,183 +3,027 +169 +Holland +3,197 +3,212 +710 +Canada +1,073 +547 +322 +Other countries +4,276 +5,162 +3,244 +Total Life Science +$ +190,136 +$ +132,535 +$ +64,332 +In locations outside the U.S., the Company’s identifiable assets were concentrated as follows at the end of the most recent fiscal years, with no additional country’s total of assets exceeding $ 5,000 : +As of September 30, +2021 +2020 +Israel +$ +80,416 +$ +70,097 +United Kingdom +30,027 +27,373 +Germany +22,293 +12,877 +Canada +15,236 +9,865 +Italy +6,921 +7,858 +- 72 - +Table of Contents +(16) +Commitments and Contingent Obligations +(a) +Royalty Commitments +- +We have entered into various license agreements that require payment of royalties based on a specified percentage of net revenues from licensed products, with such percentages generally ranging from approximately 3 % to 10 %. During the year ended September 30, 2021, royalty expense associated with these agreements totaled approximately $ 5,200 , with 25 % and 75 % +of such expense relating to our Diagnostics and Life Science segments, respectively. These royalty expenses are recognized as the related revenues are earned and are recorded as a component of cost of sales. Annual royalty expenses associated with these agreements totaled approximately +$ 1,900 and $ 2,100 for the years ended September 30, 2020 and 2019, respectively +, with approximately 80 % and 85 %, respectively, of such expense relating to the Diagnostics segment. +(b) +Purchase Commitments +- +Excluding the operating lease commitments reflected in Note 9, w +e +have purchase commitments primarily for inventories and service items as part of the normal course of business. Commitments made under these obligations are $ 49,537 for fiscal 2022 and $ 1,758 for fiscal 2023 through fiscal 202 +6 +. No purchase commitments have been made beyond fiscal 202 +6 +. +(c) +Litigation +- +We are a party to various litigation matters from time to time that we believe are in the normal course of business. The ultimate resolution of these routine matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. Additionally, the Company has also become a party to certain legal matters that are somewhat outside the normal course of business. See Note 5 for a discussion of Magellan’s DOJ matter. +(d) +Indemnifications +- +In conjunction with certain contracts and agreements, we provide routine indemnifications related to our performance obligations. The terms of these indemnifications range in duration and in some circumstances are not explicitly defined. The maximum obligation under some such indemnifications is not explicitly stated and, as a result of our having no history of paying such indemnifications, cannot be reasonably estimated. We have no t made any payments for these indemnifications and no liability is recorded at September 30, 2021 or 2020. +(17) +Subsequent Events +On October 25, 2021, the Company’s revolving credit facility with a commercial bank was amended primarily to: (i) increase the borrowing capacity to $ 200,000 ; (ii) extend the term to October 25, 2026 ; and (iii) modify the financial covenants to more closely align with the Company’s size and strategic plans. Other details of the credit facility remain relatively unchanged. +On November 9, 2021, notification was received from the FDA that emergency use authorization (“EUA”) had been granted for the Company’s Revogene SARS-CoV-2 assay. +- 73 - +Table of Contents +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE +Following a request for proposal (“RFP”) process, effective December 22, 2020 (the “Effective Date”), the Audit Committee of the Board of Directors of Meridian selected Ernst & Young LLP (“EY”) as the Company’s independent registered public accounting firm for the Company’s fiscal year ended September 30, 2021. The Audit Committee dismissed Grant Thornton LLP (“Grant Thornton”), the Company’s current independent registered public accounting firm, effective as of the Effective Date. +Grant Thornton’s reports on the Company’s Consolidated Financial Statements as of and for the fiscal years ended September 30, 2020 and 2019 did not contain any adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principles. During the fiscal years ended September 30, 2020 and 2019, and the subsequent interim period through the Effective Date, there were: (i) no disagreements within the meaning of Item 304(a)(1)(iv) of Regulation S-K and the related instructions, between the Company and Grant Thornton, on any matters of accounting principles or practices, consolidated financial statement disclosure, or auditing scope or procedure which, if not resolved to Grant Thornton’s satisfaction, would have caused Grant Thornton to make reference thereto in their reports; and (ii) no “reportable events” within the meaning of Item 304(a)(1)(v) of Regulation S-K. +The Company requested that Grant Thornton furnish a letter addressed to the SEC stating whether or not it agrees with the above statements, and, if not, stating the respects in which it does not agree. A copy of Grant Thornton’s letter, dated December 28, 2020, was filed as Exhibit 16.1 to Meridian’s Form 8-K filed on or about December 30, 2020. +During the fiscal years ended September 30, 2020 and 2019 and the subsequent interim period through the Effective Date, neither the Company nor anyone on its behalf has consulted with EY regarding: (i) the application of accounting principles to a specific transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s Consolidated Financial Statements, and neither a written report nor oral advice was provided to the Company that EY concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing, or financial reporting issue; (ii) any matter that was the subject of a disagreement within the meaning of Item 304(a)(1)(iv) of Regulation S-K and the related instructions; or (iii) any “reportable event” within the meaning of Item 304(a)(1)(v) of Regulation S-K. +ITEM 9A. +CONTROLS AND PROCEDURES +As of September 30, 2021, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of September 30, 2021. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2021. +Our internal control report is included in this Form 10-K after Item 8, under the caption “Management’s Report on Internal Control over Financial Reporting.” +- 74 - +Table of Contents +ITEM 9B. +OTHER INFORMATION +On November 19, 2021 David C. Phillips, Chairman of the Board, notified the Board of Directors that he would not be standing for +re-election +at the 2022 Annual Meeting of Shareholders. Meridian is grateful for Mr. Phillips’ 21 years of loyal service and wishes him well in his future endeavors. +Also, effective November 19, 2021 Tony Serafini-Lamanna, Executive Vice President, Diagnostics and the Company entered into a Change in Control Agreement (“CIC Agreement”), the form of which is filed with this report as Exhibit 10.11. +The CIC agreement has an initial term ending December 31, 2021, and each year will automatically renew for an additional +one-year +term, provided however, that if a change in control occurs the term will expire no earlier than 24 calendar months after the calendar month in which such change in control occurs. This agreement is the result of Management’s and the Board’s periodic review and updates of certain policies and practices. The CIC Agreement provides, among other things, that if a change in control occurs during the term of the CIC Agreement, and the executive’s employment is terminated either by us or by the executive, other than: (a) by us for cause; (b) by reason of death or disability; or (c) by the executive without good reason, such executive will receive a severance payment equal to: (A) a multiple of such executive’s annual base salary; (B) a multiple of executive’s target bonus amounts; and (C) earned but unused vacation time. In addition, the CIC Agreement provides that in the event that the severance and other benefits provided for in the agreement or otherwise payable to the executive would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code, the benefits under the CIC Agreement will be either delivered in full or delivered to a lesser extent which would result in no portion of the benefits being subject to such excise tax, whichever is more beneficial to the executive. +PART III. +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information about our directors and officers may be found under the captions “Election of Directors” and “Directors and Executive Officers” in our Proxy Statement for the Annual Meeting of Shareholders to be held January 26, 2022 (the “Proxy Statement”). Information about our Audit Committee may be found under the caption “Committees of the Board of Directors” in the Proxy Statement. That information is incorporated herein by reference. +We have adopted a code of ethics that applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, and other finance organization employees. The code of ethics is publicly available on our website at +www.meridianbioscience.com +. If we make any substantive amendments to the code of ethics or grant any waiver, including any implicit waiver, from a provision of the code to our Chief Executive Officer, Chief Financial Officer, or Chief Accounting Officer, we will disclose the nature of the amendment or waiver on that website or in a report on Form 8-K. +ITEM 11. +EXECUTIVE COMPENSATION +The information in the Proxy Statement set forth under the captions “Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” is incorporated herein by reference. +- 75 - +Table of Contents +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The information in the Proxy Statement set forth under the captions “Security Ownership of Certain Beneficial Owners” and “Equity Compensation Plan Information” is incorporated herein by reference. +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The information set forth in the Proxy Statement under the captions “Corporate Governance” and “Transactions with Related Persons” is incorporated herein by reference. +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information concerning principal accountant fees and services appears in the Proxy Statement under the headings “Principal Accounting Firm Fees” and “Committees of the Board of Directors” and is incorporated herein by reference. +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) +(1) and (2) FINANCIAL STATEMENTS AND SCHEDULES. +All financial statements and schedules required to be filed by Item 8 of this Form and included in this report have been so identified under Item 8. No additional financial statements or schedules are being filed since the requirements of paragraph (c) under Item 15 are not applicable to Meridian. +(b) +(3) EXHIBITS. +Exhibit +Number +Description of Exhibit +3.1 +Amended Articles of Incorporation (Incorporated by reference to Meridian’s Form 10-K filed with the Securities and Exchange Commission (“SEC”) on November 26, 2019) +3.2 +Amended and Restated Code of Regulations (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 26, 2019) +4.1 +Description of Securities (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 26, 2019) +10.1* +Amendment No. 1 to Supplemental Benefit Agreement Dated September 23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on September 25, 2014) +- 76 - +Table of Contents +10.2* +Third Amended and Restated Employment Agreement Dated October 3, 2016 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on October 5, 2016) +10.3* +Amended and Restated Employment Agreement dated effective October 1, 2019 between Meridian and John P. Kenny (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on November 7, 2019) +10.4* +2012 Stock Incentive Plan, effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.5* +Israeli Appendix to the Meridian Bioscience, Inc. 2012 Stock Incentive Plan dated effective July 10, 2020 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2020) +10.6* +Meridian Bioscience, Inc. 2021 Omnibus Award Plan ((Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2021) +10.7* +Form of Time-Based Restricted Share Unit Award Agreement (Filed herewith) +10.8* +Form of Nonqualified Stock Option Agreement (Filed herewith) +10.9*† +Chief Executive Officer Cash-Based Incentive Compensation Plan for Fiscal Year 2021 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2020) +10.10*† +Executive Vice President Cash-Based Incentive Compensation Plan for Fiscal Year 2021 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2020) +10.11* +Form of Meridian Bioscience, Inc. Change in Control Agreement dated August 4, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2016) +10.12 +Amended and Restated Credit Agreement, dated as of October 25, 2021, by and among Meridian Bioscience, Inc., as Borrower, the Guarantors party thereto, the Lenders party thereto, PNC Bank, National Association, as administrative agent, PNC Capital Markets LLC, as joint lead arranger and sole bookrunner, and Fifth Third Bank, National Association, as joint lead arranger and syndication agent (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on October 29, 2021) +21 +List of Subsidiaries of the Registrant (Filed herewith) +23.1 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +23.2 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +31.1 +Certification of Principal Executive Officer required by Rule 13a-14(a) (Filed herewith) +31.2 +Certification of Principal Financial Officer required by Rule 13a-14(a) (Filed herewith) +- 77 - +Table of Contents +32** +Section 1350 Certification of Chief Executive Officer and Chief Financial Officer (Furnished herewith) +101.INS*** +Inline XBRL Instance Document +101.SCH*** +Inline XBRL Taxonomy Extension Schema +101.CAL*** +Inline XBRL Taxonomy Extension Calculation Linkbase +101.DEF*** +Inline XBRL Taxonomy Extension Definition Linkbase +101.LAB*** +Inline XBRL Taxonomy Extension Label Linkbase +101.PRE*** +Inline XBRL Taxonomy Extension Presentation Linkbase +104*** +Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) +* +Management Compensatory Contracts +** +Furnished, not filed +*** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. +† +Schedules to and certain portions of these exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The omitted information is not material and would likely cause competitive harm to the Registrant if publicly disclosed. The Registrant hereby agrees to furnish a copy of any omitted schedule or other portion to the SEC upon request. +Meridian will provide shareholders with any exhibit upon the payment of a specified reasonable fee, which fee shall be limited to Meridian’s reasonable expenses in furnishing such exhibit. +ITEM 16. +FORM 10-K SUMMARY +Not applicable. +- 78 - +Table of Contents +SIGNATURES +Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +MERIDIAN BIOSCIENCE, INC. +By: +/s/ Jack Kenny +Date: November 23, 2021 +Jack Kenny +Chief Executive Officer +We, the undersigned directors and officers of the Registrant, hereby severally constitute Jack Kenny and Bryan T. Baldasare, and each of them singly, our true and lawful attorneys with full power to them and each of them to sign for us, in our names in the capacities indicated below, any and all amendments to the Annual Report on Form 10-K filed with the Securities and Exchange Commission. +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. +Signature +Capacity +Date +/s/ Jack Kenny +Chief Executive Officer and Director +November 23, 2021 +Jack Kenny +/s/ Bryan T. Baldasare +Executive Vice President, Chief +November 23, 2021 +Bryan T. Baldasare +Financial Officer and Secretary +(Principal Financial and Accounting Officer) +/s/ David C. Phillips +Chairman of the Board +November 23, 2021 +David C. Phillips +/s/ James M. Anderson +Director +November 23, 2021 +James M. Anderson +/s/ Anthony P. Bihl III +Director +November 23, 2021 +Anthony P. Bihl III +/s/ Dwight E. Ellingwood +Director +November 23, 2021 +Dwight E. Ellingwood +/s/ John C. McIlwraith +Director +November 23, 2021 +John C. McIlwraith +/s/ John M. Rice, Jr. +Director +November 23, 2021 +John M. Rice, Jr. +/s/ Catherine A. Sazdanoff +Director +November 23, 2021 +Catherine A. Sazdanoff +/s/ Felicia Williams +Director +November 23, 2021 +Felicia Williams +- 7 +9 +- +Table of Contents +SCHEDULE II +Meridian Bioscience, Inc. +and Subsidiaries +Valuation and Qualifying Accounts +(Dollars in thousands) +Years Ended September 30, 2021, 2020 and 2019 +Description +Balance at +Beginning +of Period +Charged to +Costs and +Expenses +Deductions +Other (a) +Balance at +End of +Period +Year Ended September 30, 2021: +Allowance for doubtful accounts +$ +513 +$ +583 +$ +( 34 +) +$ +16 +$ +1,078 +Inventory realizability reserves +3,629 +2,703 +( 1,297 +) +( 38 +) +4,997 +Valuation allowances – deferred taxes +895 +729 +— +— +1,624 +Year Ended September 30, 2020: +Allowance for doubtful accounts +$ +537 +$ +34 +$ +( 75 +) +$ +17 +$ +513 +Inventory realizability reserves +2,441 +1,775 +( 564 +) +( 23 +) +3,629 +Valuation allowances – deferred taxes +666 +335 +( 106 +) +— +895 +Year Ended September 30, 2019: +Allowance for doubtful accounts +$ +310 +$ +347 +$ +( 100 +) +$ +( 20 +) +$ +537 +Inventory realizability reserves +1,971 +930 +( 448 +) +( 12 +) +2,441 +Valuation allowances – deferred taxes +302 +364 +— +— +666 +(a) +Balances reflect the effects of currency translation. +- 80 - \ No newline at end of file diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/filing_metadata.csv b/raw/filings/0000794172/2021/0001193125-21-337663/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..b44e672c456a8e4e87fe6a4f6e732fe0d5ff54b1 --- /dev/null +++ b/raw/filings/0000794172/2021/0001193125-21-337663/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000794172,VIVO,MERIDIAN BIOSCIENCE INC,10-K,2021-11-23,2021-09-30,2021-11-23T13:46:09.000Z,0001193125-21-337663,d228317d10k.htm,10-K,11880738,1,1,https://www.sec.gov/Archives/edgar/data/794172/000119312521337663/d228317d10k.htm,https://www.sec.gov/Archives/edgar/data/794172/000119312521337663/,2021,2021,1 diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/item1.txt b/raw/filings/0000794172/2021/0001193125-21-337663/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..cf3122c8b51debf2ada9638c6eecba9d3988e3e6 --- /dev/null +++ b/raw/filings/0000794172/2021/0001193125-21-337663/item1.txt @@ -0,0 +1,22 @@ +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in: (i) the development, manufacture, sale and distribution of diagnostic testing systems and kits, primarily for certain gastrointestinal and respiratory infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, and bioresearch reagents used by other diagnostic test manufacturers and researchers in immunological and molecular tests for human, animal, plant and environmental applications. +Our website is +www.meridianbioscience.com +. We make available our Annual Reports on Form +10-K, +Quarterly Reports on Form +10-Q, +Current Reports on Form +8-K, +Proxy Statements and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the SEC. The SEC maintains an internet site containing these filings and other information regarding Meridian at +www.sec.gov +. The information on our website is not and should not be considered part of this Form +10-K. +Reportable Segments +Our reportable segments are Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. We describe these reportable segments in this “Business” section and in other locations in this report: +Type of Segment Information +Location within Form +10-K +Physical locations and activities \ No newline at end of file diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/item13.txt b/raw/filings/0000794172/2021/0001193125-21-337663/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..c67a44ce3b92d890209de84771c974711e457e7e --- /dev/null +++ b/raw/filings/0000794172/2021/0001193125-21-337663/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The information set forth in the Proxy Statement under the captions “Corporate Governance” and “Transactions with Related Persons” is incorporated herein by reference. \ No newline at end of file diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/item9a.txt b/raw/filings/0000794172/2021/0001193125-21-337663/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..8b6640e1de5f7a9ca443b8bd010f39acb4a1c77d --- /dev/null +++ b/raw/filings/0000794172/2021/0001193125-21-337663/item9a.txt @@ -0,0 +1,6 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +As of September 30, 2021, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of September 30, 2021. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2021. +Our internal control report is included in this Form 10-K after Item 8, under the caption “Management’s Report on Internal Control over Financial Reporting.” +- 74 - +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/rp_note.txt b/raw/filings/0000794172/2021/0001193125-21-337663/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000794172/2021/0001193125-21-337663/rpt_disclosure.txt b/raw/filings/0000794172/2021/0001193125-21-337663/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..9eb4ae311ca54cb3db588cb7a2fb4d0585463034 --- /dev/null +++ b/raw/filings/0000794172/2021/0001193125-21-337663/rpt_disclosure.txt @@ -0,0 +1,9 @@ +TRANSACTIONS WITH RELATED PERSONS +Nasdaq rules require the Company to conduct an appropriate review of related party transactions required to be disclosed by the Company pursuant to SEC Regulation S-K Item 404 for potential conflict of interest situations on an ongoing basis and that all such transactions must be approved by the Audit Committee or another Committee comprised of independent directors. As a +result, the Audit Committee annually reviews all such related party transactions and approves each related party transaction if it determines that it is in the best interests of the Company. Additionally, the Audit Committee’s Charter provides +it the authority to review, approve and monitor transactions involving the Company and “related persons” (directors and executive officers or their immediate family members, or shareholders owning five percent or greater of the +Company’s outstanding stock). This also covers any related person transaction that meets the minimum threshold for disclosure in the proxy statement under the relevant SEC rules (generally, transactions involving amounts exceeding $120,000 in +which a related person has a direct or indirect material interest). In considering the transaction, the Audit Committee may consider all relevant factors, including, as applicable: (i) the Company’s business rationale for entering into the +transaction; (ii) the alternatives to entering into a related person transaction; (iii) whether the transaction is on terms comparable to those available to third parties, or in the case of employment relationships, to employees generally; +(iv) the potential for the transaction to lead to an actual or apparent conflict of interest and any safeguards imposed to prevent such actual or apparent conflicts; and (v) the overall fairness of the transaction to the Company. This +policy is included in the Company’s Employee Handbook. The approvals of such related person transactions are evidenced by internal Company resolutions, minutes or memoranda. \ No newline at end of file diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/filing.txt b/raw/filings/0000794172/2022/0001193125-22-290521/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..92f1f374b11c33106d93b6015e0f03269c8576b7 --- /dev/null +++ b/raw/filings/0000794172/2022/0001193125-22-290521/filing.txt @@ -0,0 +1,3660 @@ +10-K +Table of Contents +Yes false FY 0000794172 Yes No Yes 0000794172 2021-10-01 2022-09-30 0000794172 2020-10-01 2021-09-30 0000794172 2019-10-01 2020-09-30 0000794172 2021-09-30 0000794172 2022-09-30 0000794172 2020-09-30 0000794172 2022-03-31 0000794172 2022-10-31 0000794172 2022-04-01 2022-04-30 0000794172 2021-02-01 2021-02-01 0000794172 2021-02-01 0000794172 2021-07-01 0000794172 2022-07-07 0000794172 2022-07-07 2022-07-07 0000794172 2019-09-30 0000794172 vivo:DiagnosticsMember country:US 2019-10-01 2020-09-30 0000794172 country:IT vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 country:GB vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember country:BE 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember country:NL 2019-10-01 2020-09-30 0000794172 vivo:OtherCountriesMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 country:KR vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember country:US 2019-10-01 2020-09-30 0000794172 country:DE vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:CN vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:GB vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:FR vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:ES vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:FI vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:TR vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:JP vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:AU vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:IT vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:IN vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:OtherCountriesMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 currency:CZK vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 country:CH vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 srt:ConsolidationEliminationsMember 2019-10-01 2020-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2019-10-01 2020-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2019-10-01 2020-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2019-10-01 2020-09-30 0000794172 vivo:ConsolidationEliminationMember 2019-10-01 2020-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ThreeDiagnosticsProductFamiliesMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember us-gaap:OperatingSegmentsMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember 2019-10-01 2020-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember vivo:OneOfTheDiagnositicOrLifeScienceSegmentCustomerMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 vivo:OneSingleCustomerMember us-gaap:SalesRevenueNetMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 vivo:ForeignCustomersMember us-gaap:SalesRevenueNetMember 2019-10-01 2020-09-30 0000794172 us-gaap:CorporateMember 2019-10-01 2020-09-30 0000794172 vivo:CustomerAMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 vivo:CustomerBMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 vivo:CustomerCMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerDMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerEMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerFMember us-gaap:CustomerConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 srt:ChiefExecutiveOfficerMember vivo:AmendedAndRestatedEmploymentAgreementMember 2019-10-01 2020-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2019-10-01 2020-09-30 0000794172 us-gaap:CommonStockMember 2019-10-01 2020-09-30 0000794172 us-gaap:RetainedEarningsMember 2019-10-01 2020-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2019-10-01 2020-09-30 0000794172 vivo:AmendedAndRestatedEmploymentAgreementMember srt:ChiefExecutiveOfficerMember us-gaap:RestrictedStockUnitsRSUMember 2019-10-01 2020-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-10-01 2020-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2019-10-01 2020-09-30 0000794172 srt:AmericasMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 us-gaap:EMEAMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:OtherForeignMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 srt:AmericasMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 us-gaap:EMEAMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:OtherForeignMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:MolecularAssaysMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DiagnosticsMember vivo:NonMolecularAssaysMember 2019-10-01 2020-09-30 0000794172 vivo:MolecularReagentsMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:ImmunologicalReagentsMember vivo:LifeScienceMember 2019-10-01 2020-09-30 0000794172 vivo:OtherDiagnosticsMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:BloodChemistryAssaysMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:RespiratoryIllnessAssaysMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:GastrointestinalAssaysMember vivo:DiagnosticsMember 2019-10-01 2020-09-30 0000794172 vivo:DOJSubpoenaMember 2019-10-01 2020-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LeaseElementsMember vivo:ReagentRentalArrangementsMember us-gaap:ProductConcentrationRiskMember 2019-10-01 2020-09-30 0000794172 srt:MinimumMember 2019-10-01 2020-09-30 0000794172 srt:MaximumMember 2019-10-01 2020-09-30 0000794172 srt:MinimumMember 2020-10-01 2021-09-30 0000794172 srt:MaximumMember 2020-10-01 2021-09-30 0000794172 country:US vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 country:IT vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 country:GB vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember country:BE 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember country:NL 2020-10-01 2021-09-30 0000794172 vivo:OtherCountriesMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 country:KR vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember country:US 2020-10-01 2021-09-30 0000794172 country:DE vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:CN vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:GB vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:FR vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:ES vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:FI vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:TR vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:JP vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:AU vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:IT vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:IN vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:OtherCountriesMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 currency:CZK vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 country:CH vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 srt:ConsolidationEliminationsMember 2020-10-01 2021-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2020-10-01 2021-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2020-10-01 2021-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2020-10-01 2021-09-30 0000794172 vivo:ConsolidationEliminationMember 2020-10-01 2021-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ThreeDiagnosticsProductFamiliesMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember us-gaap:OperatingSegmentsMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember vivo:VivoLifeScienceMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember vivo:VivoLifeScienceMember vivo:VivoCustomerEMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:OneOfTheDiagnositicOrLifeScienceSegmentCustomerMember 2020-10-01 2021-09-30 0000794172 vivo:OneSingleCustomerMember us-gaap:SalesRevenueNetMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 vivo:ForeignCustomersMember us-gaap:SalesRevenueNetMember 2020-10-01 2021-09-30 0000794172 us-gaap:CorporateMember 2020-10-01 2021-09-30 0000794172 vivo:CustomerAMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 vivo:CustomerBMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 vivo:CustomerCMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerDMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerEMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerFMember us-gaap:CustomerConcentrationRiskMember 2020-10-01 2021-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2020-10-01 2021-09-30 0000794172 us-gaap:CommonStockMember 2020-10-01 2021-09-30 0000794172 us-gaap:RetainedEarningsMember 2020-10-01 2021-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2020-10-01 2021-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2020-10-01 2021-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2020-10-01 2021-09-30 0000794172 srt:AmericasMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 us-gaap:EMEAMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:OtherForeignMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 srt:AmericasMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 us-gaap:EMEAMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:OtherForeignMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:MolecularAssaysMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:DiagnosticsMember vivo:NonMolecularAssaysMember 2020-10-01 2021-09-30 0000794172 vivo:MolecularReagentsMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:ImmunologicalReagentsMember vivo:LifeScienceMember 2020-10-01 2021-09-30 0000794172 vivo:OtherDiagnosticsMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:BloodChemistryAssaysMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:RespiratoryIllnessAssaysMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:GastrointestinalAssaysMember vivo:DiagnosticsMember 2020-10-01 2021-09-30 0000794172 vivo:BreathtekmemberMember 2020-10-01 2021-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2020-10-01 2021-09-30 0000794172 vivo:ExalenzMember 2020-10-01 2021-09-30 0000794172 vivo:DOJSubpoenaMember 2020-10-01 2021-09-30 0000794172 us-gaap:SalesRevenueNetMember us-gaap:ProductConcentrationRiskMember vivo:ReagentRentalArrangementsMember vivo:LeaseElementsMember 2020-10-01 2021-09-30 0000794172 vivo:GenepocIncMember 2020-10-01 2021-09-30 0000794172 us-gaap:CostOfSalesMember 2020-10-01 2021-09-30 0000794172 us-gaap:OperatingExpenseMember 2020-10-01 2021-09-30 0000794172 us-gaap:CustomerRelationshipsMember vivo:BreathtekmemberMember 2020-10-01 2021-09-30 0000794172 srt:MinimumMember 2021-10-01 2022-09-30 0000794172 srt:MaximumMember 2021-10-01 2022-09-30 0000794172 country:US vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 country:IT vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 country:GB vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:DiagnosticsMember country:BE 2021-10-01 2022-09-30 0000794172 vivo:DiagnosticsMember country:NL 2021-10-01 2022-09-30 0000794172 vivo:OtherCountriesMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 country:KR vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:LifeScienceMember country:US 2021-10-01 2022-09-30 0000794172 country:DE vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:CN vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:GB vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:FR vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:ES vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:FI vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:TR vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:JP vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:AU vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:IT vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:IN vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:OtherCountriesMember vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 currency:CZK vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 country:CH vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:DiagnosticsMember us-gaap:OperatingSegmentsMember 2021-10-01 2022-09-30 0000794172 vivo:LifeScienceMember us-gaap:OperatingSegmentsMember 2021-10-01 2022-09-30 0000794172 us-gaap:OperatingSegmentsMember 2021-10-01 2022-09-30 0000794172 srt:ConsolidationEliminationsMember 2021-10-01 2022-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2021-10-01 2022-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2021-10-01 2022-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2021-10-01 2022-09-30 0000794172 vivo:ConsolidationEliminationMember 2021-10-01 2022-09-30 0000794172 us-gaap:ProductConcentrationRiskMember vivo:ThreeDiagnosticsProductFamiliesMember us-gaap:SalesRevenueNetMember 2021-10-01 2022-09-30 0000794172 us-gaap:SalesRevenueNetMember us-gaap:CustomerConcentrationRiskMember vivo:OneSingleCustomerMember 2021-10-01 2022-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:OneOfTheDiagnositicOrLifeScienceSegmentCustomerMember 2021-10-01 2022-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember us-gaap:OperatingSegmentsMember 2021-10-01 2022-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember vivo:LifeScienceSegmentTenLargestCustomerMember 2021-10-01 2022-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember vivo:VivoCustomerAMemberMember vivo:VivoDiagnosticsMember 2021-10-01 2022-09-30 0000794172 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember srt:MinimumMember 2021-10-01 2022-09-30 0000794172 us-gaap:BuildingAndBuildingImprovementsMember srt:MinimumMember 2021-10-01 2022-09-30 0000794172 us-gaap:BuildingAndBuildingImprovementsMember srt:MaximumMember 2021-10-01 2022-09-30 0000794172 us-gaap:MachineryAndEquipmentMember srt:MinimumMember 2021-10-01 2022-09-30 0000794172 srt:MaximumMember us-gaap:MachineryAndEquipmentMember 2021-10-01 2022-09-30 0000794172 us-gaap:ComputerEquipmentMember srt:MinimumMember 2021-10-01 2022-09-30 0000794172 us-gaap:ComputerEquipmentMember srt:MaximumMember 2021-10-01 2022-09-30 0000794172 vivo:InstrumentsUnderCustomerReagentRentalArrangementsMember 2021-10-01 2022-09-30 0000794172 us-gaap:LeaseholdImprovementsMember 2021-10-01 2022-09-30 0000794172 vivo:ForeignCustomersMember us-gaap:SalesRevenueNetMember 2021-10-01 2022-09-30 0000794172 us-gaap:CorporateMember 2021-10-01 2022-09-30 0000794172 vivo:CustomerAMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 vivo:CustomerBMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 vivo:CustomerCMember us-gaap:SalesRevenueNetMember vivo:DiagnosticsMember vivo:SegmentLevelMember us-gaap:CustomerConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerDMember us-gaap:CustomerConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerEMember us-gaap:CustomerConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LifeScienceMember vivo:SegmentLevelMember vivo:CustomerFMember us-gaap:CustomerConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2021-10-01 2022-09-30 0000794172 us-gaap:TreasuryStockMember 2021-10-01 2022-09-30 0000794172 vivo:StockIncentivePlanTwentyTwentyOneMember 2021-10-01 2022-09-30 0000794172 vivo:StockIncentivePlanMember 2021-10-01 2022-09-30 0000794172 us-gaap:CommonStockMember 2021-10-01 2022-09-30 0000794172 vivo:MilestoneMember vivo:PerformanceBasedRestrictedStockUnitsMember 2021-10-01 2022-09-30 0000794172 us-gaap:RetainedEarningsMember 2021-10-01 2022-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2021-10-01 2022-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2021-10-01 2022-09-30 0000794172 us-gaap:DomesticCountryMember 2021-10-01 2022-09-30 0000794172 us-gaap:ForeignCountryMember 2021-10-01 2022-09-30 0000794172 srt:MaximumMember vivo:MilestoneMember vivo:PerformanceBasedRestrictedStockUnitsMember 2021-10-01 2022-09-30 0000794172 srt:MinimumMember vivo:MilestoneMember vivo:PerformanceBasedRestrictedStockUnitsMember 2021-10-01 2022-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2021-10-01 2022-09-30 0000794172 srt:AmericasMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 us-gaap:EMEAMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:OtherForeignMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 srt:AmericasMember vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 us-gaap:EMEAMember vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:OtherForeignMember vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:MolecularAssaysMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:DiagnosticsMember vivo:NonMolecularAssaysMember 2021-10-01 2022-09-30 0000794172 vivo:MolecularReagentsMember vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:ImmunologicalReagentsMember vivo:LifeScienceMember 2021-10-01 2022-09-30 0000794172 vivo:GastrointestinalAssaysMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:OtherDiagnosticsMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:BloodChemistryAssaysMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:RespiratoryIllnessAssaysMember vivo:DiagnosticsMember 2021-10-01 2022-09-30 0000794172 vivo:BreathtekmemberMember 2021-10-01 2022-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2021-10-01 2022-09-30 0000794172 vivo:BreathIdProductsMember 2021-10-01 2022-09-30 0000794172 vivo:DOJSubpoenaMember 2021-10-01 2022-09-30 0000794172 us-gaap:SalesRevenueNetMember vivo:LeaseElementsMember vivo:ReagentRentalArrangementsMember us-gaap:ProductConcentrationRiskMember 2021-10-01 2022-09-30 0000794172 us-gaap:CostOfSalesMember 2021-10-01 2022-09-30 0000794172 us-gaap:OperatingExpenseMember 2021-10-01 2022-09-30 0000794172 us-gaap:BuildingAndBuildingImprovementsMember 2021-10-01 2022-09-30 0000794172 vivo:BreathtekmemberMember us-gaap:CustomerRelationshipsMember 2021-10-01 2022-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2021-09-30 0000794172 vivo:InstrumentsMember 2021-09-30 0000794172 vivo:KitsAndReagentsMember 2021-09-30 0000794172 us-gaap:DomesticCountryMember 2021-09-30 0000794172 us-gaap:ForeignCountryMember 2021-09-30 0000794172 us-gaap:OperatingSegmentsMember vivo:DiagnosticsMember 2021-09-30 0000794172 us-gaap:OperatingSegmentsMember vivo:LifeScienceMember 2021-09-30 0000794172 vivo:ConsolidationEliminationMember 2021-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2021-09-30 0000794172 country:IT 2021-09-30 0000794172 country:CA 2021-09-30 0000794172 country:DE 2021-09-30 0000794172 country:GB 2021-09-30 0000794172 country:IL 2021-09-30 0000794172 us-gaap:CashMember 2021-09-30 0000794172 us-gaap:MoneyMarketFundsMember 2021-09-30 0000794172 us-gaap:NoncompeteAgreementsMember 2021-09-30 0000794172 vivo:CustomerListsAndRelationshipsAndSupplyAgreementsMember 2021-09-30 0000794172 vivo:TradeNamesLicensesAndPatentsMember 2021-09-30 0000794172 vivo:ManufacturingTechnologiesCoreProductsAndCellLinesMember 2021-09-30 0000794172 srt:MaximumMember vivo:GenepocIncMember vivo:FinancialPerformanceTargetsMember 2021-09-30 0000794172 vivo:GenepocIncMember srt:MaximumMember vivo:ProductDevelopmentMilestonesMember vivo:OnAcquisitionDateMember 2021-09-30 0000794172 vivo:GenepocIncMember srt:MaximumMember vivo:ProductDevelopmentMilestonesMember 2021-09-30 0000794172 vivo:GenepocIncMember srt:MaximumMember vivo:ProductDevelopmentMilestonesAndFinancialPerformanceTargetsMember vivo:OnAcquisitionDateMember 2021-09-30 0000794172 vivo:ProductDevelopmentMilestonesAndFinancialPerformanceTargetsMember vivo:GenepocIncMember srt:MaximumMember 2021-09-30 0000794172 vivo:NationalInstituteOfHealthMember vivo:ReimbursementOfResearchAndDevelopmentExpenditureAccruedMember 2021-09-30 0000794172 vivo:FormerChiefExecutiveOfficerMember 2021-09-30 0000794172 vivo:PotentialFutureSeveranceIndemnityMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:InterestRateSwapMember 2021-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2022-09-30 0000794172 vivo:InstrumentsMember 2022-09-30 0000794172 vivo:KitsAndReagentsMember 2022-09-30 0000794172 us-gaap:ForeignCountryMember 2022-09-30 0000794172 vivo:StockIncentivePlanTwentyTwentyOneMember 2022-09-30 0000794172 vivo:StockIncentivePlanMember 2022-09-30 0000794172 us-gaap:OperatingSegmentsMember vivo:DiagnosticsMember 2022-09-30 0000794172 us-gaap:OperatingSegmentsMember vivo:LifeScienceMember 2022-09-30 0000794172 vivo:ConsolidationEliminationMember 2022-09-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2022-09-30 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2022-09-30 0000794172 us-gaap:EmployeeStockOptionMember 2022-09-30 0000794172 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2022-09-30 0000794172 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2022-09-30 0000794172 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:InterestRateSwapMember 2022-09-30 0000794172 us-gaap:InterestRateSwapMember 2022-09-30 0000794172 country:IT 2022-09-30 0000794172 country:CA 2022-09-30 0000794172 country:DE 2022-09-30 0000794172 country:GB 2022-09-30 0000794172 country:IL 2022-09-30 0000794172 srt:MaximumMember vivo:LongTermGovernmentGrantObligationsMember 2022-09-30 0000794172 srt:MinimumMember vivo:LongTermGovernmentGrantObligationsMember 2022-09-30 0000794172 us-gaap:CashMember 2022-09-30 0000794172 us-gaap:MoneyMarketFundsMember 2022-09-30 0000794172 us-gaap:NoncompeteAgreementsMember 2022-09-30 0000794172 vivo:CustomerListsAndRelationshipsAndSupplyAgreementsMember 2022-09-30 0000794172 vivo:TradeNamesLicensesAndPatentsMember 2022-09-30 0000794172 vivo:ManufacturingTechnologiesCoreProductsAndCellLinesMember 2022-09-30 0000794172 vivo:FormerChiefExecutiveOfficerMember 2022-09-30 0000794172 vivo:PotentialFutureSeveranceIndemnityMember 2022-09-30 0000794172 vivo:EuproteinMember 2022-09-30 0000794172 vivo:GenepocIncMember 2019-06-03 0000794172 vivo:GenepocIncMember 2021-08-01 2021-08-31 0000794172 vivo:BreathtekmemberMember 2021-07-01 2021-07-31 0000794172 vivo:BreathtekmemberMember us-gaap:CustomerRelationshipsMember 2021-07-01 2021-07-31 0000794172 vivo:BreathtekmemberMember 2021-07-31 0000794172 us-gaap:CustomerRelationshipsMember vivo:BreathtekmemberMember 2021-07-31 0000794172 us-gaap:RestrictedStockUnitsRSUMember 2019-10-01 2022-09-30 0000794172 us-gaap:OperatingSegmentsMember vivo:DiagnosticsMember 2020-09-30 0000794172 us-gaap:OperatingSegmentsMember vivo:LifeScienceMember 2020-09-30 0000794172 vivo:ConsolidationEliminationMember 2020-09-30 0000794172 vivo:EuproteinMember 2022-04-30 0000794172 us-gaap:RevolvingCreditFacilityMember 2022-03-01 2022-03-31 0000794172 us-gaap:AdditionalPaidInCapitalMember 2019-09-30 0000794172 us-gaap:RetainedEarningsMember 2019-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-09-30 0000794172 us-gaap:TreasuryStockMember 2019-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2019-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2019-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2019-09-30 0000794172 us-gaap:CommonStockMember 2019-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2020-09-30 0000794172 us-gaap:InventoryValuationReserveMember 2020-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2020-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2020-09-30 0000794172 us-gaap:RetainedEarningsMember 2020-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2020-09-30 0000794172 us-gaap:TreasuryStockMember 2020-09-30 0000794172 us-gaap:CommonStockMember 2020-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2021-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2021-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2021-09-30 0000794172 us-gaap:RetainedEarningsMember 2021-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2021-09-30 0000794172 us-gaap:TreasuryStockMember 2021-09-30 0000794172 us-gaap:CommonStockMember 2021-09-30 0000794172 us-gaap:AllowanceForCreditLossMember 2022-09-30 0000794172 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2022-09-30 0000794172 us-gaap:AdditionalPaidInCapitalMember 2022-09-30 0000794172 us-gaap:RetainedEarningsMember 2022-09-30 0000794172 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2022-09-30 0000794172 us-gaap:TreasuryStockMember 2022-09-30 0000794172 us-gaap:CommonStockMember 2022-09-30 iso4217:USD xbrli:pure xbrli:shares utr:Year utr:Month iso4217:USD xbrli:shares vivo:Stock-Plan +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM +10-K +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED SEPTEMBER 30 , 2022 . +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM +TO +Commission File No. 0-14902 +MERIDIAN BIOSCIENCE, INC. +3471 River Hills Drive +Cincinnati , Ohio 45244 +IRS Employer ID No. 31-0888197 +State of Incorporation: Ohio +Phone: ( 513 ) 271-3700 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Trading Symbol +Name of each exchange on which registered +Common Shares, No Par Value +VIVO +The NASDAQ Stock Market LLC +(NASDAQ Global Select Market) +Securities registered pursuant to Section 12(g) of the Act: +None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ☒ ☐ +NO +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES ☐ ☒ +NO +Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ☒ NO ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES ☒ NO ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +☒ +Accelerated filer +☐ +Non-accelerated +filer +☐ +Smaller reporting company +☐ +Emerging growth company +☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). YES ☐ NO ☒ +The aggregate market value of Common Shares held by non-affiliates as of March 31, 2022 was $ 1,124,567,912 based on a closing sale price of $25.96 per share on March 31, 2022. As of October 31, 2022, 43,827,819 shares of Common Stock, no par value, were issued and outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Items 10, 11, 12, 13 and 14 of Part III will be provided within a separate filing within 120 days of the Company’s September 30, 2022 fiscal year end and is incorporated herein by reference. Portions of the Proxy Statement related to the proposed Merger filed on September 8, 2022 are incorporated by reference in Part III of this report. +Table of Contents +MERIDIAN BIOSCIENCE, INC. +INDEX TO ANNUAL REPORT +ON FORM 10-K +Page +Part I +Item 1 +Business +5 +Item 1A +Risk Factors +12 +Item 1B +Unresolved Staff Comments +25 +Item 2 +Properties +25 +Item 3 +Legal Proceedings +26 +Item 4 +Mine Safety Disclosures +27 +Part II +Item 5 +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +27 +Item 6 +Intentionally Omitted +28 +Item 7 +Management’s Discussion and Analysis of Financial Condition and Results of Operations +28 +Item 7A +Quantitative and Qualitative Disclosures about Market Risk +39 +Item 8 +Financial Statements and Supplementary Data +40 +Item 9 +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +74 +Item 9A +Controls and Procedures +74 +Item 9B +Other Information +75 +Item 9C +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections +75 +Part III +Item 10 +Directors, Executive Officers and Corporate Governance +75 +Item 11 +Executive Compensation +75 +Item 12 +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +75 +Item 13 +Certain Relationships and Related Transactions, and Director Independence +75 +Item 14 +Principal Accountant Fees and Services +75 +Item 15 +Exhibits and Financial Statement Schedules +75 +Item 16 +Form 10-K Summary +77 +NOTE ABOUT FORWARD-LOOKING STATEMENTS +This report includes estimates, projections, statements relating to our business plans, objectives, and expected operating results that are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements may appear throughout this report, including the following sections: “Business” (Part I, Item 1 of this Form 10-K), “Risk Factors” (Part I, Item 1A of this Form 10-K), and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Part II, Item 7 of this Form 10-K). These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “future,” “opportunity,” “plan,” “may,” “should,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties that may cause actual results to differ materially. We describe risks and uncertainties that could cause actual results and events to differ materially in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” (Part II, Item 7A of this Form 10-K) and elsewhere in this Form 10-K. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date they are made. We undertake no obligation to update or revise publicly any forward-looking statements, whether because of new information, future events, the novel coronavirus (“COVID-19”) pandemic, or otherwise. +Table of Contents +Unless the context requires otherwise, references in this Annual Report on Form 10-K (“Form 10-K”) to “Meridian,” “we,” “us,” “our,” “Company,” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +In the discussion that follows, all dollar amounts and share amounts are in thousands (both tables and text), except per share data. +This Form 10-K refers to trademarks such as Alethia ® , BreathID ® , BreathTek ® , Curian ® , HpSA ® , Immuno Card ® , Immuno Card STAT! ® , LeadCare ® , MyTaq™, PREMIER ® , revogene ® and SensiFAST™, which are protected under applicable intellectual property laws and are our property. Solely for convenience, our trademarks and tradenames referred to in this Form 10-K may appear without the ® or ™ symbols, but such references are not intended to indicate in any way that we will not assert, to the fullest extent under applicable law, our rights to these trademarks and tradenames. Our molecular diagnostic test platform formerly known under the tradenames illumi gene and illumi pro , has been rebranded under the tradename Alethia. References to Alethia throughout this Form 10-K refer to our molecular diagnostic tests and instrumentation formerly marketed and sold under the illumi gene and illumi pro brands. Such references are not intended to indicate, in any way, that we will not assert, to the fullest extent permitted by law, our rights to our trademarks. +WEBSITE AND SOCIAL MEDIA DISCLOSURE +We use our website ( www.meridianbioscience.com ) and our corporate Facebook, Instagram, LinkedIn, Twitter, Vimeo and YouTube accounts as channels of distribution of company information. The information we post through these channels may be deemed material. Accordingly, investors should monitor these channels, in addition to following our press releases, Securities and Exchange Commission (“SEC”) filings and public conference calls and webcasts. The contents of our website and social media channels are not, however, a part of this report. +MARKET AND INDUSTRY INFORMATION +Market data used throughout this Form 10-K is based on management’s knowledge of the industry and good faith estimates of management. All of management’s estimates presented herein are based on industry sources, including analyst reports and management’s knowledge. We also relied, to the extent available, upon management’s review of independent industry surveys and publications prepared by a number of sources and other publicly available information. We are responsible for all of the disclosures in this Form 10-K and while we believe that each of the publications, studies and surveys used throughout this Form 10-K are prepared by reputable sources, we have not independently verified market and industry data from third-party sources. +All of the market data used in this Form 10-K involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. While we believe the estimated market position, market opportunity and market size information included in this Form 10-K is generally reliable, such information, which in part is derived from management’s estimates and beliefs, is inherently uncertain and imprecise and has not been verified by any independent source. Projections, assumptions and estimates of our future performance and the future performance of the industry in which we operate are subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Item 1A. Risk Factors” of Part I of this Form 10-K and elsewhere in this Form 10-K. These and other factors could cause results to differ materially from those expressed in our estimates and beliefs and in the estimates prepared by independent parties. +- 4 - +Table of Contents +PART I. +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in: (i) the development, manufacture, sale and distribution of diagnostic testing systems and kits, primarily for certain gastrointestinal and respiratory infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, and bioresearch reagents used by other diagnostic test manufacturers and researchers in immunological and molecular tests for human, animal, plant and environmental applications. +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statements and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the SEC. The SEC maintains an internet site containing these filings and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered part of this Form 10-K. +Pending Merger +On July 7, 2022, the Company entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “Merger Agreement”) with SD Biosensor, Inc., a corporation with limited liability organized under the laws of the Republic of Korea (“SDB”), Columbus Holding Company, a Delaware corporation (“Parent”), and Madeira Acquisition Corp., an Ohio corporation and a direct wholly owned subsidiary of Parent (“Merger Sub”). Meridian is informed that SJL Partners, LLC (“SJL”) is currently the sole shareholder of Parent, and SDB together with SJL will be the sole shareholders of Parent as of the closing of the Merger. Pursuant to the Merger Agreement, Merger Sub will merge with and into Meridian (the “Merger”), with Meridian surviving the Merger as a direct wholly owned subsidiary of Parent. Consummation of the Merger is subject to customary closing conditions, including, without limitation: (i) the absence of certain legal impediments; and (ii) the condition that no Specified Outcome, as such term is defined in the Merger Agreement, related to the DOJ LeadCare legal matter (which is described in the section entitled “Legal Matter Relating to LeadCare Product Line” of Item 3. “Legal Proceedings”) has occurred or is reasonably likely to occur. +On November 21, 2022, the parties received clearance from the Committee on Foreign Investment in the United States with respect to the Merger and the transactions contemplated by the Merger Agreement. +The foregoing description of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Merger Agreement, which is attached as an exhibit to our Current Report on Form 8-K filed with the SEC on July 7, 2022. +Reportable Segments +Our reportable segments are Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. We describe these reportable segments in this “Business” section and in other locations in this report: +Type of Segment Information +Location within Form 10-K +Physical locations and activities +Item 2. “Properties” +Net revenues by geographic region +Item 8. “Note 2 of Consolidated Financial Statements” +Financial information +Item 8. “Note 15 of Consolidated Financial Statements” +- 5 - +Table of Contents +Diagnostics Segment +Products and Markets +Prior to the onset of the COVID-19 pandemic early in 2020, our largest source of net revenues was clinical diagnostic products, historically representing approximately two-thirds of our consolidated net revenues. However, primarily due to the effects of the COVID-19 pandemic, which led to the growth in our Life Science segment, our Diagnostics segment provided 47% of consolidated net revenues for fiscal 2022, following 40% of consolidated net revenues for fiscal 2021. +Our clinical diagnostic products provide accuracy, simplicity and speed; enable early diagnosis and treatment of acute medical conditions; and provide for better patient outcomes at reduced costs. We target diagnostics for disease states that: (i) are conditions where rapid diagnosis impacts patient outcomes; (ii) have opportunistic demographic and disease profiles; (iii) are underserved by current diagnostic products; and/or (iv) have difficult sample handling requirements (e.g., stool). This approach has allowed us to establish meaningful market share in our target disease states, gastrointestinal and respiratory illnesses, and tests for elevated lead levels in blood. +Our product portfolio includes approximately 200 diagnostic tests and transport media, and is marketed to acute care hospitals, reference laboratories, outpatient clinics and physician office laboratories in over 70 countries around the world. Our testing platforms include: Real-time PCR Amplification (Revogene brand); Isothermal DNA Amplification (Alethia brand); Lateral Flow Immunoassay using fluorescent chemistry (Curian brand); Rapid Immunoassay (Immuno Card and Immuno Card STAT! brands); Enzyme-linked Immunoassay (PREMIER brand); Anodic Stripping Voltammetry (LeadCare brands); and urea breath testing for H. pylori (BreathID and BreathTek brands). +Our diagnostic assay research and development programs are focused on menu expansion for our Curian and Revogene instrument platforms, with disease targets in the gastrointestinal and respiratory areas, as well as next generation blood-chemistry testing. Currently pending clearance at the U.S. Food and Drug Administration (“FDA”) is a 510(k) application for our Curian EHEC Shiga Toxin assay. Our current new product development pipeline includes gastrointestinal and respiratory multi-plex assays on our Revogene instrument platform, and C. difficile combo common antigen and Toxins A and B, on our Curian instrument platform. In addition, we have other assays on both platforms moving through our upstream marketing assessment processes that are expected to add to the development pipeline. For our BreathID platform, we are actively looking at the feasibility of combining Urea and Citrica into a single sachet or pouch. We are also pursuing opportunities to complement our internal research and development programs by securing rights to finished diagnostics tests that we can immediately commercialize. +The April 2020 acquisition of Exalenz Bioscience Ltd. (“Exalenz”) and the BreathID system, along with the July 2021 acquisition of the BreathTek business, strengthened our position in H. pylori testing, as these products provide an alternative testing approach versus stool antigen testing. +Market Trends +Despite the effects of the COVID-19 pandemic and the intense focus on SARS-CoV-2 testing, we believe the global market for infectious disease tests continues to expand as new disease states are identified, new therapies become available, and worldwide standards of living and access to health care improve. There is a continuing shift from conventional testing to more technologically advanced testing, which can be performed by less highly trained personnel and completed in minutes or hours. +The growing global pressures to contain total health care costs have accelerated the increased use of diagnostic testing. Integrated Delivery Networks (“IDNs”) in our U.S. market have the goal of increasing the efficiency of health care delivery, reducing spending and improving clinical outcomes. We believe our product portfolio positions us competitively with IDNs and health care systems that are transitioning from fee-for-service compensation models to value-based reimbursement. +- 6 - +Table of Contents +We also continue to see aggregation of buying power in our U.S. market via multi-hospital group purchasing organizations (“GPOs”) and IDNs, consolidation among reference laboratories, hospital laboratories being operated by large reference laboratories, and acquisition of physician practices by hospitals, health systems and for-profit specialty health care companies. +Cost containment pressures have also affected health care systems outside the U.S., particularly in Europe, where the health care systems are generally government-run. The level of government budget deficits can have an adverse effect on the amount of government health care spend. +Sales, Marketing and Distribution +Our Diagnostics segment relies on direct sales personnel and independent distribution networks. We have a direct sales force in two countries, covering the United States (“U.S.”) and certain major markets in the EMEA region (i.e., in Europe, the Middle East and Africa). We also use independent distributors either in a complementary manner with our direct sales force (e.g., the U.S.) or solely to supply our products to end-users. We have two independent distribution customers and a reference laboratory customer that together comprised 29% of Diagnostics segment net revenues in fiscal 2022, with each contributing between 8% and 11% of the Diagnostics segment’s net revenues. +Competition +Our major competitors in molecular diagnostics are Cepheid (a Danaher business) and Becton Dickinson, both of which have systems with multiple-assay menus. We also face competition in molecular diagnostics, but to a lesser degree, from companies such as Abbott (former Alere business) and QuidelOrtho. In recent years, companies such as bioMerieux have captured market share in our gastrointestinal category via its BioFire multi-plex panel tests. However, since their introduction to the market, payors have raised concerns over reimbursement levels relative to clinical utility, particularly for panels with 12 or more targets. Our major competitors in rapid immunoassay diagnostics are primarily Abbott (former Alere business) and QuidelOrtho. +For blood lead testing, we believe we have the only FDA-cleared, CLIA-waived point-of-care test available commercially. Other blood lead testing systems in use, marketed by our competitors, include Graphite Furnace Atomic Absorption Spectroscopy, which requires a highly skilled technician and larger laboratory space to operate, in addition to not being portable or suitable for point-of-care use. +Research and Development +Our Diagnostics segment’s research and development personnel are organized into three pre-clinical teams: immunoassay, PCR-based molecular and blood-chemistry. We have a separate team responsible for execution of clinical trials across all three pre-clinical programs. Our research and development activities are focused on new product and new technology development, new applications for our existing technologies, and improvements to existing products, including assay-menu expansion. Research and development efforts may occur in-house or with collaborative partners. We believe that new product development is a key source for sustaining revenue growth. The products within our Revogene and Alethia molecular platforms, H. pylori product family and blood lead testing family were developed in-house. +Manufacturing +Our diagnostics products are manufactured at four principal sites in Billerica, Massachusetts (blood-chemistry); Cincinnati, Ohio (immunoassays and molecular tests); Modi’in, Israel, (urea breath tests for H. pylori ); and Quebec City, Quebec, Canada (molecular tests). Our immunoassay and molecular assay products require the production of highly specialized reagents, primers and enzymes, and our BreathID and BreathTek products require the production of urea in pharmaceutical-grade form. We produce the vast majority of our own immunoassay requirements. Reagents, primers and enzymes for our Revogene molecular assay products, primers for our Alethia molecular assay products, and urea for our BreathID and BreathTek systems are purchased from outside vendors. Our blood lead testing products require the production of electrical chemical sensors, which we manufacture using critical raw materials purchased from outside vendors. +- 7 - +Table of Contents +Intellectual Property, Patents and Licenses +We own or license U.S. and foreign patents, most of which are for select products manufactured by our Diagnostics segment. These patents are used in our manufacturing processes for select products (e.g., method patents) or may relate to the design of the test device technology format (e.g., design patents). In the absence of patent protection, we may be vulnerable to competitors who successfully replicate our production and manufacturing technologies and processes. Our employees are required to sign confidentiality and non-disclosure agreements designed to protect our proprietary products. +The patents applicable to our Alethia products, which represented 3%, 4% and 7% of consolidated net revenues for fiscal 2022, 2021 and 2020, respectively, were licensed from a third party, Eiken Chemical Co., Ltd., under a non-exclusive license agreement, with the last remaining U.S. patent having expired during the year ended September 30, 2022. +The patents for the Revogene platform and related products acquired as part of the GenePOC business are either wholly owned or licensed from two third parties, Laval University and The Regents of California, under an exclusive license agreement. These patents are issued in the U.S., European Union (“EU”) and other countries. The term of our exclusive license agreement and the related patents currently runs through June 15, 2034, after which we will be free to practice the patents without any restriction or royalty obligation. In September 2021, the U.S. Patent and Trademark Office granted to Meridian Bioscience Canada, Inc. (a wholly owned subsidiary) and Laval University a patent for our current Revogene test device and its microfluidic use in our Revogene instrument. +The patents for the BreathID system and related urea breath test for H. pylori are either wholly owned or licensed from a third party, Oridion Medical 1987 Ltd., under an exclusive, royalty free, license agreement. The licensed and wholly owned patents are issued in the U.S., EU, Israel, Japan, Australia and China. The wholly owned patents have varying expiration dates, with the last being in 2033. +The patents for our stool antigen H. pylori products, owned by us and which represented approximately 5%, 7% and 9% of consolidated net revenues for fiscal 2022, 2021 and 2020, respectively, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. As a result, competition with respect to our stool antigen H. pylori products has increased, adversely impacting our selling prices for these products, and/or our ability to retain business at prices acceptable to us. To mitigate certain of the pricing and volume pressures we face within the gastrointestinal product category, we have: (i) operated under a strategic collaboration agreement with DiaSorin to sell H. pylori tests; (ii) adjusted selling prices to secure volume; and (iii) upon FDA clearance in March 2020, launched Curian HpSA, our first assay on the Curian platform, which we expect will help protect our existing customer base using lateral flow tests. We also expect the BreathID and BreathTek products to mitigate competitive pressures, as these products provide an alternative to stool antigen testing. We are unable to provide assurances that we will be successful with any strategy or that any strategy will prevent an adverse effect on our future results of operations and/or liquidity, including net revenues and gross profit. +Government Regulation +Our diagnostic products are regulated by the FDA as “devices” pursuant to the Federal Food, Drug, and Cosmetic Act (“FDCA”). Under the FDCA, medical devices are classified into one of three classes (i.e., Class I, II or III). While exempt Class I and Class II products do not require FDA review, non-exempt Class I and Class II devices are “cleared” for marketing (i.e., these products require FDA review prior to marketing clearance). Class III devices generally must receive “pre-market approval” (“PMA”) from the FDA as to safety and effectiveness. Our diagnostics manufacturing facilities are subject to periodic inspection by the FDA. See “Lead Testing Matters” beginning on page 32 within MD&A for discussion regarding the FDA’s inspection of our Billerica facility. +Each of the diagnostic products currently marketed by Meridian in the U.S. has been cleared, approved or authorized for use by the FDA or are exempt from such requirements. The majority of such products have been cleared by the FDA pursuant to its 510(k) premarket review process, whereas our BreathTek product has been approved under the FDA’s PMA process. In the case of our Revogene SARS-CoV-2 test, it has not been FDA cleared or approved but rather has been authorized by the FDA for emergency use under its Emergency Use Authorization (“EUA”) process, noting that there will likely be modifications to the regulatory requirements related to these tests in the near future when the EUA is revoked. We believe that most products under development will be classified as Class I or II medical devices and, in the case of most of our Class I and all Class II devices, will be eligible for 510(k) clearance; however, we can make no assurances in this regard. Our urea breath test for H. pylori on the BreathID system was cleared as a Class I medical device since the urea drug component was approved by the FDA separately via the New Drug Application (“NDA”) process. Our urea breath test for H. pylori on the BreathTek system was approved by the FDA via the PMA process in 2012. Following receipt of EUA on November 9, 2021 for our original SARS-CoV-2 test, our Omicron variant enhanced SARS-CoV-2 test on the Revogene platform was submitted to the FDA under its EUA program on March 29, 2022, with EUA being granted on July 27, 2022. +- 8 - +Table of Contents +Sales of our diagnostic products in foreign countries are subject to foreign government regulation, which is similar to that of the FDA. Our Diagnostics segment facilities are certified to ISO 13485. +Following a five-year transition period, sales of our diagnostic products in the EU are subject to new regulations under the In Vitro Diagnostics Regulation of 2017 (“IVDR”) beginning in May 2022. IVDR replaces the previous IVD Regulation (98/79/EC). In October 2021, the European Commission submitted a proposal to the European Parliament that would move back the May 2022 implementation date for diagnostic tests that are currently CE Marked to dates ranging from May 2022 (for Class A products) to May 2027 (for Class B products), depending on the risk classification of the diagnostic test. We have completed an assessment of needed remediation activities to comply with IVDR and also determined that several products will not be sellable under IVDR. The net revenues associated with these products are not expected to be material. New diagnostic products launched after May 2022 are required to comply with IVDR. +Life Science Segment +Products and Markets +Our Life Science segment develops, manufactures, sells and distributes bulk antigens, antibodies, immunoassay blocking reagents, specialized PCR master mixes, isothermal reagents, enzymes, nucleotides, and bioresearch reagents used predominantly by in vitro device (“IVD”) manufacturing companies, and to a lesser degree, by researchers and non-human clinical customers such as veterinary, food and environmental. The COVID-19 pandemic has provided the opportunity for our Life Science segment to showcase the breadth of its reagent products across not only SARS-CoV-2 testing platforms (molecular, rapid antigen and serology), but also RNA and DNA based molecular tests for nearly any infectious disease. For fiscal 2022, approximately 87% of Life Science segment net revenues were generated from the industrial market, defined as IVD manufacturers. Further, as it relates to our Life Science segment net revenues, a significant number of our Life Science segment customers now use our molecular reagents in multiple tests, including non-COVID-19 related tests, therefore making it increasingly difficult to accurately estimate the portion of molecular reagent sales related specifically to COVID-19. As a result, we are no longer reporting the portion of Life Science segment net revenues related to COVID-19. Such net revenues were identified and reported throughout fiscal 2021 and fiscal 2020, totaling approximately $111,900 and $71,500, respectively. We engage direct sales teams in the U.S., the United Kingdom (“U.K.”), France, Germany, China and Australia. During fiscal 2022, 28% of net revenues for this segment were from two IVD manufacturing customers. +Our Life Science segment products are marketed to IVD manufacturing customers as a source of raw materials for their human clinical diagnostics tests, or as an outsourced step in their manufacturing processes. Independent distributors market our molecular biology products to academic/research customers. Our products are used in detecting DNA and RNA in human, animal, plant and environmental applications. +Market Trends +Major IVD manufacturing customers often have global footprints, where we are supplying reagents to specific manufacturing sites around the world. IVD manufacturers in specific countries of the Asia-Pacific region (e.g., China) are increasing their efforts in the development and manufacturing of infectious disease tests. We intend to use the breadth of our product portfolio, particularly molecular reagents, to continue to increase the penetration of our products in IVD manufacturing customers’ tests. +Competition +The market for bulk biomedical reagents is highly competitive with respect to product quality, price, customer service and reputation. Our competitors, such as Thermo Fisher, often have greater financial, research and development, sales and marketing, and manufacturing resources. Customers also may choose to manufacture their biomedical reagents in-house rather than purchase from us. +- 9 - +Table of Contents +Research and Development +Our research and development activities for the Life Science segment focus on molecular reagents for use in PCR and isothermal chemistries in detecting both DNA and RNA. Our new product development programs are progressing through sample-specific (e.g., blood, saliva, urine, stool, and plant) mixes in both air-dryable and lyophilization-ready forms, and isothermal reagents in both air-dryable and lyophilization-ready forms. We also have enzyme development programs that meet the EU Registration, Evaluation, Authorization, and Restriction of Chemicals regulation. See “Operating Expenses” section on page 36 within MD&A. Additionally, through our recent EUPROTEIN, Inc. (“EUPROTEIN”) and Estel Biosciences, Inc. (“Estel”) transactions in April 2022 and October 2022, respectively, we have expanded our immunological research and development capabilities. See the following notes of the Consolidated Financial Statements for further discussion of these transactions: (i) Note 4, “Business Combinations” for EUPROTEIN, and Note 18, “Subsequent Event” for Estel. +Manufacturing and Government Regulation +Our Life Science segment facilities are ISO 13485 certified, and where appropriate, our Life Science segment facilities comply with Regulation EC 1069. +International Markets +International markets are an important source of net revenues and future growth opportunities for both of our reportable segments. For both reportable segments combined, net revenues from customers located outside of the U.S. and its territories approximated $170,000 or 51% of consolidated 2022 net revenues, $173,000 or 55% of consolidated 2021 net revenues, and $122,000 or 48% of consolidated 2020 net revenues. Since the outbreak of the COVID-19 pandemic in fiscal 2020 and throughout fiscal 2021 and 2022, a significantly higher percentage of our Life Science segment’s net revenues have been generated from international markets, and we expect to continue to look to key European and Asian markets as a source of revenue growth. For the Life Science segment, we also continue to focus resources on IVD manufacturing customers in China, India, Japan and Korea. To date, we have not experienced any adverse effects from the trade tensions between the U.S. and China, but we cannot be sure that we will not experience any adverse effects in the future. +Fluctuations in foreign currency exchange rates in fiscal 2022 compared to fiscal 2021 had an approximate $5,200 unfavorable impact on consolidated 2022 net revenues; $1,700 within the Diagnostics segment and $3,500 within the Life Science segment. This compares to year-to-year currency exchange rates having an approximate $9,200 favorable impact on consolidated net revenues in 2021; $1,300 within the Diagnostics segment and $7,900 within the Life Science segment. In fiscal 2020, the unfavorable effect on net revenues totaled $1,250; $150 within the Diagnostics segment and $1,100 within the Life Science segment. +Environmental +We are in compliance with applicable portions of the federal and state hazardous waste regulations and have never been a party to any environmental proceeding. +Human Capital +As of September 30, 2022, our Diagnostics segment had approximately 515 employees in eight countries, our Life Science segment had approximately 210 employees in six countries, and Corporate and Shared Services had approximately 45 employees, all in the U.S. Approximately 57% of our employees are women. In addition, of our U.S. based employees, which represents approximately 65% of our total worldwide workforce, approximately 25% are ethnically diverse. +Below is additional demographic information about our current employee base as of September 30, 2022. +Meridian Employees +2022 +Salaried workforce +529 +Managers and above +161 +Part-time employees +27 +Average age +43 +Average length of service in years +7 +Employee turnover rate (voluntary) +25 +% +Fiscal 2022 net revenues per employee (in thousands) +$ +432 +- 10 - +Table of Contents +Equal Employment Opportunity Table (by number of employees) +U.S. Employee Diversity as of September 30, 2022 +Job category +Gender +White +Black/African +American +Hispanic/Latino +Asian +American +Indian/Alaskan +Native +Two +or +more +races +Total +Executive/senior level officials and managers +Male +10 +— +— +1 +— +— +11 +Female +2 +— +1 +— +— +— +3 +First/mid-level officials and managers +Male +47 +5 +2 +2 +— +— +56 +Female +40 +3 +— +4 +— +— +47 +Professionals +Male +51 +6 +3 +4 +— +2 +66 +Female +65 +10 +6 +10 +— +3 +94 +All other +Male +74 +7 +4 +9 +— +— +94 +Female +84 +14 +7 +13 +— +2 +120 +Total +Male +182 +18 +9 +16 +— +2 +227 +Female +191 +27 +14 +27 +— +5 +264 +We believe that developing a diverse, equitable and inclusive culture is critical to continuing to attract and retain the top talent necessary to deliver on our growth strategy. As such, we continue to invest in the creation of a work environment where our employees can feel inspired to deliver their workplace best every day. We continue to expand our Human Resources Information System (“HRIS”) and other systems to track key human capital metrics, including workforce demographics, diversity, turnover, engagement, and training data. +Diversity, Equity and Inclusion +In 2020, we initiated the “One Meridian Inclusion Diversity and Equity Team,” which is comprised of a group of employees around the world and led by Dr. Lourdes Weltzien, Executive Vice President, Life Science, and Melissa McCarey, Vice President, Global Human Resources. Consistent with its mission statement, this team is providing topical programs throughout the year, in an effort to promote awareness so we can encourage and support an environment in which all employees feel included and empowered to achieve their best. +Compensation and Benefits +We strive to provide pay, benefits, and services that are competitive to market and create incentives to attract and retain employees globally. Our compensation packages include market-competitive pay, cash bonuses, health care and retirement benefits, paid time off, and family leave, among others, depending upon locale. We are focused on pay equity globally and are striving to close the gap in pay among similar roles and responsibilities in certain locations within our organization, after accounting for legitimate business factors that can explain differences, such as performance, time at grade level, and tenure. We intend to conduct market surveys every two years to assess market compensation levels from a total compensation perspective. We also continue to advance transparency in our pay and representation data by complying with all applicable statutory filing requirements. +Communication and Engagement +We strongly believe that Meridian’s success depends on employees understanding how their work contributes to the Company’s overall strategy. To this end, we utilize a variety of channels to facilitate open and direct communication, including: (i) One Meridian Company-wide intranet; (ii) quarterly CEO update videos; (iii) open forums or town hall meetings with executives; (iv) regular ongoing update communications; and (v) employee engagement surveys. +Health, Wellness and Safety +We are committed to the safety of our employees and communities, and safety in our operations, our product development activities and our supplier partnerships. Our ultimate goal is to achieve zero serious injuries through continued investment in, and focus on, our core safety programs and injury-reduction initiatives. We provide access to a variety of innovative, flexible, and convenient health and wellness tools. +- 11 - +Table of Contents +ITEM 1A. +RISK FACTORS +In addition to the other information set forth in this report, you should carefully consider the following factors, which could materially affect our business, financial condition, cash flows and/or future results. Any one of these factors could cause our actual results to vary materially from recent results or from anticipated future results. The risks described below are not the only risks facing our company. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may materially adversely affect our business, financial condition and/or operating results. +Risk Factors Summary +Risks Related to Our Strategy +• +If the Merger contemplated by the Merger Agreement does not occur, it could have a material adverse effect on our business, results of operations, financial condition and stock price. +• +Our financial condition, results of operations and cash flows could be adversely affected by outbreaks of disease, such as the COVID-19 pandemic. +• +Net revenues for our Diagnostics segment may be impacted by our reliance upon large customers in North America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +• +Net revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +• +Intense competition could adversely affect our profitability and operating results. +• +We expect to continue facing increased competition resulting from the expiration of our H. pylori patents. +Risks Related to our Intellectual Property +• +We may be unable to protect or obtain adequate patent protection for intellectual property that we utilize or intend to utilize. +• +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Risks Related to our Operations +• +We may be unable to develop new products or acquire products on favorable terms. +• +We may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions we make. +• +The effective tax rate of the Company may be negatively impacted by changes in the mix of earnings as well as future changes to tax laws in global jurisdictions in which we operate. +• +Significant interruptions in production at our principal manufacturing facilities and/or third-party manufacturing facilities could adversely affect our business and operating results. +• +We depend on sole-source suppliers for certain critical raw materials, components and finished products. A supply interruption could adversely affect our business. +• +Our ability to meet future customer demand for selected products is dependent upon our ability to successfully manage our manufacturing capacity and supply chains. +• +Increased prices for, poor quality of, or extended inability to source raw materials or services used in our products, and supply chain disruptions, could adversely affect profitability. +Risks Related to Legal, Regulatory and International Matters +• +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +• +If we or our third-party vendors fail to comply with FDA regulations relating to the manufacturing of our products or any component part, we may be subject to fines, injunctions and penalties, and our ability to commercially distribute and sell our products may be negatively impacted. +- 12 - +Table of Contents +• +We incur costs and demands upon management as a result of complying with the laws and regulations affecting public companies in the U.S., and failure to comply with these laws could harm our business and the price of our common stock. +• +We could be adversely affected by health care reform legislation. +• +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +• +Global market, political, environmental, and economic conditions, including those related to the financial markets, could have a material adverse effect on our operating results, financial condition, and liquidity. +• +We depend on international net revenues, and our operating results may be adversely impacted by foreign currency, regulatory or other developments affecting international markets. +• +New tariffs and other trade measures could adversely affect our operating results. +• +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and may have to limit or cease sales of our products. +Risks Related to Our Common Stock +• +The market price of our common stock may be volatile and fluctuate significantly, which could result in substantial losses for stockholders and subject us to litigation. +• +Our business could be negatively impacted as a result of shareholder activism, an unsolicited takeover proposal or a proxy contest. +• +The authority of our board to issue preferred stock and the effects of certain provisions of Ohio corporation law may discourage takeover bids. +General Risk Factors +• +One or more cybersecurity incidents may adversely impact our financial condition, results of operations and/or reputation. +• +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +• +Our bank credit agreement imposes restrictions with respect to our operations, which could adversely impact our business. +Risks Related to Our Strategy +If the Merger contemplated by the Merger Agreement does not occur, it could have a material adverse effect on our business, results of operations, financial condition and stock price. +On July 7, 2022, we entered into the Merger Agreement noted above within the “Pending Merger” section of Item 1. “Business.” Completion of the proposed Merger is subject to the satisfaction of various conditions. There is no assurance that all of the various conditions will be satisfied, or that the Merger will be completed within the expected timeframe, or at all. The proposed Merger gives rise to inherent risks that include: +• +the amount of the cash to be paid under the Merger Agreement is fixed and will not be adjusted for changes in our business, assets, liabilities, prospects, outlook, financial condition or results of operations or in the event of any change in the market price of, analyst estimates of, or projections relating to, our common stock; +• +legal or regulatory proceedings, or other matters that affect the timing or ability to complete the transaction as contemplated; +• +the possibility of disruption to our business, including increased costs and diversion of management time and resources; +• +difficulties maintaining business and operational relationships, including relationships with clients, vendors, suppliers, distributors, resellers and other business partners; +• +the inability to attract and retain key personnel pending consummation of the proposed Merger; +- 13 - +Table of Contents +• +potential stockholder litigation relating to the Merger could prevent or delay the Merger or otherwise negatively impact our business and operations; +• +the inability to pursue alternative business opportunities or make changes to our business pending the completion of the proposed Merger; +• +developments beyond our control including, but not limited to, changes in domestic or global economic conditions that may affect the timing or success of the proposed Merger; and +• +the risk that if the proposed Merger is not completed, the market price of our common stock could decline, investor confidence could decline, stockholder litigation could be brought against us, relationships with clients, suppliers and other business partners may be adversely impacted, we may be unable to retain key personnel, and profitability may be adversely impacted due to costs incurred in connection with the proposed Merger and general disruption to our business. +Our financial condition, results of operations and cash flows could be adversely affected by outbreaks of disease, such as the COVID-19 pandemic. +Any outbreak of contagious diseases, such as COVID-19, or other adverse public health developments, could have material and adverse effects on our business operations. Such adverse effects could include diversion or prioritization of health care resources away from the conduct of diagnostic testing, disruptions of or restrictions on the ability of laboratories to process our tests, and delays or difficulties with respect to patients accessing our tests, including those resulting from an inability to travel as a result of quarantines or other restrictions resulting from such outbreaks. As COVID-19 continues to affect individuals and businesses around the globe, we may experience disruptions that could severely impact our business, including: +• +decreased volume of testing and related sales of certain of our Diagnostics segment products as a result of disruptions to health care providers and limitations on the ability of providers to administer tests; +• +disruptions or restrictions on the ability of the Company’s, our collaborators’, or our suppliers’ personnel to travel, and temporary closures of our facilities, or the facilities of our collaborators or suppliers; +• +limitations on employee resources that would otherwise be focused on the development of our products, the processing of our diagnostic tests, and/or the conduct of our clinical trials, because of illness of employees or their families, or requirements imposed on employees to avoid contact with large groups of people; and +• +delays in necessary interactions with local regulators, ethics committees, and other important agencies and contractors due to limitations in employee resources or forced furlough of government employees. +In addition, the continued spread of COVID-19 globally could adversely affect our manufacturing and supply chains. Parts of our direct and indirect supply chains are located overseas, including in China, and may accordingly be subject to disruption. Additionally, our results of operations could be adversely affected to the extent that COVID-19 or any other epidemic harms our business or the economy in general either domestically or in any other region in which we do business. The extent to which COVID-19 affects our operations will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration of the outbreak, new information that may emerge concerning the severity of COVID-19, and the actions to contain COVID-19 or treat its impact, among others, which could have an adverse effect on our business, results of operations and financial condition. Over the course of the COVID-19 pandemic, we have generally seen a slowing of our assay instrument placements and sales of related test kits, as diagnostic testing sites turned their attention to critical care testing. We are unable to predict when expected sales volume levels for our instruments and related test kits will return. Also, as a result of the COVID-19 pandemic, certain clinical trials related to our products which were underway or scheduled to begin were temporarily placed on hold. Such delays have impacted our timing for filing applications for product clearances with the FDA, as well as related timing of FDA clearances of such filings. Additionally, the COVID-19 pandemic slowed efforts to expand our product portfolio through acquisition opportunities, impacting the speed with which we are able to bring additional products to market. +- 14 - +Table of Contents +Net revenues for our Diagnostics segment may be impacted by our reliance upon large customers in North America, seasonal factors and sporadic outbreaks, and changing diagnostic market conditions. +Key Distributors +Our Diagnostics segment’s net revenues from sales through three customers, including two key distributors, were approximately 29%, 33% and 32% of the Diagnostics segment’s total net revenues for 2022, 2021 and 2020, respectively, or approximately 13%, 13% and 15%, respectively, of each year’s consolidated net revenues. The loss of any one of these customers could negatively impact our net revenues and results of operations unless suitable alternatives were timely found or in the case of distributor customers, lost sales to one distributor were absorbed by another distributor. Finding a suitable alternative on satisfactory terms may pose challenges in our industry’s competitive environment. As an alternative, we could expand our efforts to distribute and market our products directly. This alternative, however, would require substantial investment in additional sales, marketing and logistics resources, including hiring additional sales and customer service personnel, which would significantly increase our future selling, general and administrative expenses. +In addition, buying patterns of these customers may fluctuate from quarter to quarter, potentially leading to uneven concentration levels on a quarterly basis. +Seasonal Factors and Sporadic Outbreaks +Our principal business is the sale of a broad range of diagnostic test kits for common gastrointestinal and respiratory infectious diseases, and elevated blood lead levels. Certain infectious diseases may be seasonal in nature, while others may be associated with sporadic outbreaks, such as foodborne illnesses or pandemics such as an influenza outbreak or the COVID-19 pandemic. While we believe that the breadth of our Diagnostics segment product lines normally reduces the risk that infections subject to seasonality and sporadic outbreaks will cause significant variability in Diagnostics segment net revenues, the COVID-19 pandemic has had a significant adverse impact on our Diagnostics segment net revenues since it began in fiscal 2020. Accordingly, we can make no assurance that net revenues will not be negatively impacted period over period by such factors. +Changing Diagnostic Market Conditions +Changes in the U.S. health care delivery system have resulted in consolidation among reference laboratories, hospital laboratories being operated by large reference laboratories, and the formation of multi-hospital alliances, reducing the number of institutional customers for diagnostic test products. Consolidation in the U.S. health care industry has also led to the creation of GPOs and IDNs that aggregate buying power for hospital groups and put pressure on our selling prices. Due to such consolidation, we may not be able to enter into and/or sustain contractual or other marketing or distribution arrangements on a satisfactory commercial basis with institutional customers, GPOs and/or IDNs, which could adversely affect our results of operations. +Net revenues for our Life Science segment may be impacted by customer concentrations and buying patterns. +Our Life Science segment’s net revenues from three diagnostic manufacturing customers were 31%, 20% and 24% of the Life Science segment’s total net revenues for 2022, 2021 and 2020, respectively. Sales to these three diagnostic manufacturing customers comprised 17%, 12% and 13% of consolidated net revenues for 2022, 2021 and 2020, respectively. In addition, in excess of 10% of the Life Science segment’s total net revenues has historically been concentrated among a number of other significant customers. Any significant alteration of buying patterns from these customers resulting from the decline in COVID-19 related demand, or otherwise, could adversely affect our period over period net revenues and results of operations. +Intense competition could adversely affect our profitability and operating results. +The markets for our products and services are characterized by substantial competition and rapid change. Hundreds of companies around the world supply diagnostic tests and immunoassay and molecular reagents. These companies range from multinational health care entities, for which diagnostics is one line of business, to small start-up companies. Many of our competitors have significantly greater financial, technical, manufacturing and marketing resources than we do. We cannot provide assurance that our products and services will be able to compete successfully with the products and services of our competitors. +- 15 - +Table of Contents +We expect to continue facing increased competition resulting from the expiration of our H. pylori patents. +The patents for our stool antigen H. pylori products, owned by us, expired in May 2016 in the U.S. and in May 2017 in countries outside the U.S. As a result, competition with respect to our stool antigen H. pylori products, products which currently represent approximately 5% of our total net revenues has increased, adversely impacting our selling prices for these products, and/or our ability to retain business at prices acceptable to us. To mitigate certain of the pricing and volume pressures we face within the gastrointestinal product category, we have: (i) operated under a strategic collaboration agreement with DiaSorin to sell H. pylori tests; (ii) adjusted selling prices to secure volume; and (iii) upon FDA clearance in March 2020, launched Curian HpSA, our first assay on the Curian platform, which we expect will help protect our existing customer base using lateral flow tests. We also expect the BreathID and BreathTek products to mitigate competitive pressures, as these systems provide an alternative to stool antigen testing. We are unable to provide assurances that we will be successful with any strategy or that any strategy will prevent an adverse effect on our future results of operations and liquidity, including net revenues and gross profit. +Risks Related to Our Intellectual Property +We may be unable to protect or obtain adequate patent protection for intellectual property that we utilize or intend to utilize. +In developing and manufacturing our products, we employ a variety of proprietary and patented technologies. In addition, we have licensed, and expect to continue to license, various complementary technologies and methods from academic institutions and public and private companies. We cannot provide assurance that the technologies that we own or license provide protection from competitive threats or from challenges to our intellectual property. In addition, we cannot provide assurances that we will be successful in obtaining and retaining licenses, or proprietary or patented technologies, in the future. +Product infringement claims by other companies could result in costly disputes and could limit our ability to sell our products. +Litigation over intellectual property rights is prevalent in the life science and diagnostic industries. As the market for diagnostics continues to grow and the number of participants in the market increases, we may increasingly be subject to patent infringement claims. It is possible that a third party may claim infringement against us. If found to infringe, we may attempt to obtain a license to such intellectual property; however, we may be unable to do so on favorable terms, or at all. Additionally, if our products are found to infringe on third-party intellectual property, we may be required to pay damages for past infringement and lose the ability to sell certain products, causing our revenues to decrease. Any substantial loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our future results of operations and liquidity, including net revenues and gross profit. +Risks Related to Our Operations +We may be unable to develop new products or acquire products on favorable terms. +The medical diagnostic and life science industries are characterized by ongoing technological developments and changing customer requirements. As such, our results of operations and continued growth depend, in part, on our ability in a timely manner to develop or acquire rights to, and successfully introduce into the marketplace, enhancements of existing products and services, or new products and services that incorporate technological advances, meet customer requirements, and/or respond to products developed by our competition. We cannot provide any assurance that we will be successful in developing or acquiring such rights to products and services on a timely basis, or that such products and services will adequately address the changing needs of the marketplace, either of which could adversely affect our results of operations. +In addition, we must regularly allocate considerable resources to research and development of new or acquired products, services and technologies, and protecting intellectual property. The research and development process generally takes a significant amount of time from research to product launch. This process is conducted in various stages. During each stage, there is a risk that we will not achieve our goals on a timely basis, or at all, and we may have to abandon a project in which we have invested substantial resources, any of which could adversely affect our results of operations. +- 16 - +Table of Contents +We may be unable to successfully integrate operations or to achieve expected cost savings from acquisitions we make. +One of our growth strategies is the acquisition of companies and/or products. Although additional acquisitions of companies and products may enhance the opportunity to increase net earnings over time, such acquisitions could result in greater administrative burdens, increased exposure to the uncertainties inherent in marketing new products, financial risks of additional operating costs, disrupted operations, challenges in employee retention, and increased risk of asset impairments if future net revenues and cash flows are deficient. The principal benefits expected to result from any acquisitions we make will not be achieved fully unless we are able to successfully integrate the operations of the acquired entities with our operations and realize the anticipated synergies, cost savings and growth opportunities from integrating these businesses into our existing businesses. We cannot provide assurance that we will be able to identify and complete additional acquisitions on terms we consider favorable or that, if completed, will be successfully integrated into our operations. Furthermore, we cannot predict the outcome of goodwill impairment testing and the impact of goodwill impairments on the Company’s net earnings and results of operations. +The effective tax rate of the Company may be negatively impacted by changes in the mix of earnings as well as future changes to tax laws in global jurisdictions in which we operate. +We are subject to income taxes in the U.S. and various other global jurisdictions. Our effective tax rate could be adversely affected by changes in the mix of earnings by jurisdiction and the valuation of deferred tax assets and liabilities. Recently, the current U.S. presidential administration committed to tax reform, and if enacted, the impact could be material to our tax provision and value of deferred tax assets and liabilities. We recognize deferred tax assets and liabilities based on the differences between the consolidated financial statement carrying amounts and the tax basis of assets and liabilities. Significant judgment is required in determining our provision for income taxes. We regularly review our deferred tax assets for recoverability and establish a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized. If we are unable to generate sufficient future taxable income, if there is a material change in the actual effective tax rates, or if there is a change to the time period within which the underlying temporary differences become taxable or deductible, we could be required to increase our valuation allowance against our deferred tax assets, which could result in a material increase in our effective tax rate. +Changes in tax laws or tax rulings could have a material impact on our effective tax rate. Many countries in the EU, as well as several other countries and organizations such as the Organization for Economic Cooperation and Development, are actively considering changes to existing tax laws. Certain proposals could include recommendations that could increase our tax obligations in those countries where we do business. Any changes in the taxation of our activities in such jurisdictions may result in a material increase in our effective tax rate. +Significant interruptions in production at our principal manufacturing facilities and/or third-party manufacturing facilities would adversely affect our business and operating results. +Products and services manufactured at facilities we own or lease comprise a majority of our net revenues. Our global supply of these products and services is dependent on the uninterrupted and efficient operation of these facilities. In addition, we currently rely on a small number of third-party manufacturers to produce certain of our diagnostic products and product components. The operations of our facilities or these third-party manufacturing facilities could be adversely affected by power failures, or natural or other disasters such as earthquakes, floods, tornadoes or terrorist threats. Although we carry insurance to protect against certain business interruptions at our facilities, there can be no assurance that such coverage will be adequate or that such coverage will continue to remain available on acceptable terms, if at all. Any significant interruption in the Company’s or a third-party supplier’s manufacturing capabilities, including interruptions resulting from product recall activities like that experienced in our Billerica facility (see “Lead Testing Matters” beginning on page 32 within MD&A) could materially and adversely affect our results of operations. +- 17 - +Table of Contents +We depend on sole-source suppliers for certain critical raw materials, components and finished products. A supply interruption could adversely affect our business. +Raw Materials and Components +Our diagnostic products are made from a wide variety of raw materials that are biological or chemical in nature, and that generally are available from multiple sources of supply. We sole-source certain raw materials and components, which makes it time consuming and costly to switch raw materials and components in FDA-cleared products. If certain suppliers fail to supply required raw materials or components, we will need to secure other sources which may require us to conduct additional development and testing and obtain regulatory approval. These activities require significant time and resources, and there is no assurance that new sources will be secured or regulatory approvals, if necessary, will be obtained. +We utilize third-party manufacturers for certain of our instrumentation. One third party manufactures our proprietary Alethia Incubator/Reader (instrument), a component of our Alethia molecular system, and an additional third party manufactures our Curian instrument. These instruments are manufactured exclusively for Meridian according to our specifications. While other manufacturers for these types of instruments are available, we source each instrument solely from one manufacturer to limit the costs involved in clearing the system for marketing in the U.S. If these third-party manufacturers fail to supply us with instruments, we will need to secure another manufacturer, and it may take as long as 12 months to transfer instrument manufacturing. An interruption in the manufacturing of these instruments could have a material adverse effect on our results of operations. +Additionally, one third party manufactures a certain reagent for use with our Alethia assays. While alternative suppliers exist, we elect to utilize this third party exclusively in order to maintain consistency in our materials, which is critical in complying with FDA regulatory requirements. An interruption in the manufacturing of these reagents could have a material adverse effect on our results of operations. +Finished Products +We outsource the manufacturing for certain finished diagnostic products to third parties. A disruption in the supply of these finished products could have a material adverse effect on our business until we find another supplier or bring manufacturing in-house. +Activities undertaken by Meridian to reduce the risk of these sole-supplier arrangements include maintaining adequate inventory levels, supplier qualification procedures, supplier audits, site visits, and frequent communication. Additionally, we have identified potential alternate suppliers. +Our ability to meet future customer demand for selected products is dependent upon our ability to successfully manage our manufacturing capacity and supply chains. +To manage our anticipated future growth effectively, it may become necessary for us to enhance our manufacturing and supply chain capabilities, infrastructure and operations, information technology infrastructure, and financial and accounting systems and controls. Organizational growth and scale-up of operations could strain our existing managerial, operational, financial, and other resources. If our management is unable to effectively prepare for our expected future growth, our expenses may increase more than anticipated, our net revenues could grow more slowly than expected, and we may not be able to achieve our commercialization, profitability, or product development goals. Our failure to effectively implement the necessary processes and procedures and otherwise prepare for our anticipated growth could have a material adverse effect on our future consolidated financial condition and results of operations. +The Russia / Ukraine war (the “War”) that developed during the second quarter of fiscal year 2022 also could disrupt our supply chains. While to date this War has not caused us to experience any material negative impacts on our business, financial condition, or results of operations, we are unable to estimate the extent to which, if at all, the war could hurt our supply chains. The evolving nature of the War, related international sanctions, other potential government actions, and economic consequences of the War, including incurring higher costs to source materials due to inflation or otherwise, are factors that could disrupt supply chains throughout the world, including potentially the supply chains on which our business relies. If the War either directly or indirectly disrupts our supply chains and we are unable to mitigate such disruption, the War could have a material adverse effect on our future consolidated financial condition and results of operations. +- 18 - +Table of Contents +Increased prices for, poor quality of, or extended inability to source raw materials or services used in our products, and supply chain disruptions, could adversely affect profitability. +Our profitability is affected by the prices of the raw materials used in the manufacture of our products. These prices fluctuate based on a number of factors beyond our control, including changes in supply and demand, general economic conditions, labor costs, fuel-related delivery costs, competition, import duties, tariffs, currency exchange rates, and, in some cases, government regulation. Significant increases in the prices of raw materials, services and transportation costs, similar to the inflationary increases we have experienced since the second half of fiscal 2021, that cannot be recovered through increases in the price of our products and/or offset by savings in other areas, could adversely affect our results of operations and cash flows. +We cannot guarantee that the prices we are paying for raw materials today will continue in the future, or that the marketplace will continue to support current prices for our products, or that such prices can be adjusted to fully or partially offset raw material price increases in the future. Any increases in prices resulting from a tightening supply of these or other commodities could adversely affect our profitability. We do not engage in hedging transactions for raw material purchases, but we do enter into some fixed-price supply contracts. +Our dependency upon regular deliveries of supplies and the quality of those supplies upon delivery from particular suppliers means that interruptions, stoppages, or deterioration of quality in such deliveries could adversely affect our operations until arrangements with alternate suppliers could be made. Several of the raw materials used in the manufacture of our products currently are procured from a single source. In some cases, we also outsource certain services to suppliers, including but not limited to, engineering, assembly, shipping, and commissioning services. If a supplier were unable to deliver these materials or services, or if the quality of these materials or services declined, for an extended period of time as a result of financial difficulties, catastrophic events affecting their facilities, or other factors, including recent supply chain disruptions we have experienced, or if we were unable to negotiate acceptable terms for the supply of materials or services with these suppliers, our business could be adversely affected. We may not be able to find acceptable alternatives, and any such alternatives could result in increased costs. Extended inability to source a necessary raw material or service could cause us to cease manufacturing one or more products for a period of time, which could also lead to loss of customers, as well as reputational, competitive, or business harm, which could have a material adverse effect on our business, consolidated financial condition, and results of operations. +Risks Related to Legal, Regulatory and International Matters +We are subject to comprehensive regulation, and our ability to earn profits may be restricted by these regulations. +Medical device diagnostics is a highly regulated industry. We cannot provide assurance that we will be able to obtain necessary governmental clearances or approvals, or timely clearances or approvals, to market future products in the U.S. and other countries. Costs and difficulties in complying with laws and regulations administered by the FDA, the U.S. Department of Agriculture, the U.S. Department of Commerce, the U.S. Drug Enforcement Agency, the Centers for Disease Control and Prevention (“CDC”), or other regulators can result in unanticipated expenses and delays, and interruptions to the sale of new and existing products. +Regulatory approval can be a lengthy, expensive and uncertain process, making the timing and cost of approvals difficult to predict. Failure to comply with these regulations can result in delays in obtaining authorization to sell products, seizure or recall of products, suspension or revocation of authority to manufacture or sell products, and other civil or criminal sanctions. +- 19 - +Table of Contents +If we or our third-party vendors fail to comply with FDA regulations relating to the manufacturing of our products or any component part, we may be subject to fines, injunctions and penalties, and our ability to commercially distribute and sell our products may be negatively impacted. +Our diagnostics manufacturing facilities, and the manufacturing facilities of any of our third-party diagnostic component manufacturers or critical suppliers, are required to comply with the FDA’s Quality System Regulation (“QSR”), which sets forth minimum standards for the procedures, execution and documentation of the design, testing, production, control, quality assurance, labeling, packaging, sterilization, storage, and shipping of the products we sell, and related regulations, including Medical Device Reporting (“MDR”) regulations regarding reporting of certain malfunctions and adverse events potentially associated with our products. The FDA may evaluate our compliance with the QSR, MDR and other regulations, among other ways, through periodic announced or unannounced inspections which could disrupt our operations and interrupt our manufacturing. If in conducting an inspection of our manufacturing facilities, or the manufacturing facilities of any of our third-party component manufacturers or critical suppliers, an FDA investigator observes conditions or practices believed to violate the QSR, the investigator may document their observations on a Form FDA 483 that is issued at the conclusion of the inspection. A manufacturer that receives an FDA 483 may respond in writing and explain any corrective actions taken in response to the inspectional observations. The FDA will typically review the facility’s written response and may re-inspect to determine the facility’s compliance with the QSR and other applicable regulatory requirements. Failure to take adequate and timely corrective actions to remedy objectionable conditions listed on an FDA 483 could result in the FDA taking administrative or enforcement actions. Among these may be the FDA’s issuance of a Warning Letter to a manufacturer, which informs it that the FDA considers the observed violations to be of “regulatory significance” that, if not corrected, could result in further enforcement action. +FDA enforcement actions, which include seizure, injunction, criminal prosecution, and civil penalties, could result in total or partial suspension of a facility’s production and/or distribution, product recalls, fines, suspension of the FDA’s review of product applications, and/or the FDA’s issuance of adverse publicity. Thus, an adverse inspection could force a shutdown of our manufacturing operations or a recall of our products. Adverse inspections could also delay FDA approval of our products and could have an adverse effect on our production, net revenues and profitability. +We and any of our third-party vendors may also encounter other problems during manufacturing including failure to follow specific protocols and procedures, equipment malfunction, and environmental factors, any of which could delay or impede our ability to meet demand. The manufacture of our product also subjects us to risks that could harm our business, including problems relating to our facilities and errors in manufacturing components that could negatively affect the efficacy or safety of our products or cause delays in shipment of our products. Any interruption or delay in the manufacture of the product, or any of its components, could impair our ability to meet the demand of our customers and cause them to cancel orders or switch to competitive products, which could, therefore, have a material adverse effect on our business, consolidated financial condition and results of operations. +As described in Item 3. “Legal Proceedings”, on April 17, 2018, the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlined documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas, both to former employees of Magellan, calling for witnesses to testify before a federal grand jury related to this matter. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. It is the Company’s understanding that multiple witnesses have testified before the federal grand jury and the DOJ’s investigation is ongoing. Discussions continue with the DOJ to explore resolution of the matter. As of September 30, 2022, in accordance with applicable accounting guidance, the Company believes a loss is probable in the DOJ LeadCare legal matter and has accrued $10,000 as an estimate of the cost to resolve the DOJ LeadCare legal matter, which is reflected in litigation and select legal costs within the Consolidated Statement of Operations for the year ended September 30, 2022. The Company cannot predict when the investigation will be resolved or the outcome of the investigation, and the ultimate resolution of the DOJ LeadCare legal matter may exceed the amount accrued at September 30, 2022 and could be material to the Company. Expense for attorneys’ fees related to this matter totaling $3,510, $2,803 and $2,035 is included within the Consolidated Statements of Operations for the years ended September 30, 2022, 2021 and 2020, respectively. +- 20 - +Table of Contents +Magellan submitted 510(k) applications in December 2018, seeking to reinstate venous blood sample-types for its LeadCare II, LeadCare Plus and LeadCare Ultra testing systems. In the second fiscal quarter of 2019, the FDA informed Magellan that each of these 510(k) applications had been put on Additional Information hold. On July 15, 2019, we provided responses to the FDA’s requests for Additional Information. These 510(k) applications have since expired and are no longer under FDA review. Further, while Magellan’s LeadCare testing systems remain cleared for marketing by the FDA and permitted for use with capillary blood samples, the FDA advised that it has commissioned a third-party study of the Company’s LeadCare testing systems using both venous and capillary blood samples. According to the FDA, the results of the field study will be used in conjunction with other information to determine whether further action by the FDA or the CDC is necessary to protect the public health. The Company intends to fully cooperate with the FDA or CDC on any follow-up based on the third-party study. +During October 2019, the FDA performed a follow-up inspection of Magellan’s manufacturing facility. The FDA issued five Form FDA 483 observations. On March 18, 2020, we participated in a regulatory meeting with the FDA at the FDA’s request to further discuss the Form FDA 483 observations and our remediation efforts. Since the inspection, we have submitted a number of written responses to the FDA regarding the five Form FDA 483 observations issued in the October 2019 inspection, and have worked diligently to execute a remediation plan. During October 2020, the FDA issued Establishment Inspection Reports which closed out the inspections from June 2017 and October 2019 under 21 C.F.R.20.64(d)(3). +During June 2021, the FDA performed an inspection of Magellan’s manufacturing facility. As a result of this inspection, the FDA issued one Form 483 observation. On August 3, 2021, FDA sent Magellan a close-out letter for the Warning Letter that FDA issued to Magellan on October 23, 2017. The FDA’s close-out letter notified Magellan that FDA has completed an evaluation of Magellan’s corrective actions in response to FDA’s Warning Letter, and based on FDA’s evaluation, Magellan has addressed the issues identified in the Warning Letter. FDA’s close-out letter also stated that future FDA inspections of Magellan and regulatory activities will further assess the adequacy and sustainability of Magellan’s corrections. +We incur costs and demands upon management as a result of complying with the laws and regulations affecting public companies in the U.S., and failure to comply with these laws could harm our business and the price of our common stock. +As a public company listed in the U.S., we incur significant legal, accounting and other expenses. In addition, changing laws, regulations and standards relating to corporate governance and public disclosure, including regulations implemented by the SEC, the Public Company Accounting Oversight Board (“PCAOB”) and the NASDAQ Global Select Market, may increase our legal and financial compliance costs and/or make some activities more time consuming. These laws, regulations and standards are subject to varying interpretations and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. If we fail to comply with new laws, regulations and standards, regulatory authorities may initiate legal proceedings against us, and our business may be harmed. +We could be adversely affected by health care reform legislation. +Third-party payers for medical products and services, including state, federal and foreign governments, are increasingly concerned about escalating health care costs and can indirectly affect the pricing or the relative attractiveness of our products by regulating the maximum amount of reimbursement they will provide for diagnostic testing services. Following years of increasing pressure, during 2010 the U.S. government enacted comprehensive health care reform with the enactment of the Patient Protection and Affordable Care Act, as amended by the Health Care and Education Reconciliation Act, which made changes that significantly impact the pharmaceutical and medical device industries. The Protecting Access to Medicare Act of 2014 requires applicable laboratories to report all private payor reimbursement rates and the volumes for each test they perform. The statute requires that Medicare establish reimbursement rates based on the weighted median of private insurance reimbursement rates effective January 1, 2017. The new Medicare rates would be subject to a maximum reduction of 10% a year for the initial three-year period and a maximum of 15% a year for the subsequent three-year period. There is no limit on the amount of potential rate increases. As a result, some of our customers in the U.S. may experience lower Medicare reimbursement rates for our products, which may adversely affect our business, financial condition and results of operations. We are seeing some effect on the reimbursement rates for our products. If reimbursement amounts for diagnostic testing services decrease further in the future, such decreases may reduce the amount that will be reimbursed to hospitals or physicians for such services and consequently, could place constraints on the levels of overall pricing, which could have a material effect on our net revenues and results of operations. +- 21 - +Table of Contents +Additional state and federal health care reform measures may be adopted in the future, any of which could have a material adverse effect on our ability to successfully commercialize our products and on our industry in general. For example, the U.S. government has in the past considered, is currently considering, and may in the future consider, health care policies and proposals intended to curb rising health care costs, including those that could significantly affect both private and public reimbursement for health care services. Further, state and local governments, as well as a number of foreign governments, are also considering or have adopted similar types of policies. Future significant changes in the health care system in the U.S. or elsewhere, and current uncertainty about whether and how changes may be implemented, could have a negative impact on the demand for our products. We are unable to predict whether health care policies, including policies stemming from legislation or regulations affecting our business, may be proposed or enacted in the future, what effect such policies would have on our business, or the effect that ongoing uncertainty about these matters will have on the purchasing decisions of our customers. +Efforts to reduce the U.S. federal deficit could adversely affect our results of operations. +Any reductions in government health care spending or research funding in an effort to reduce the U.S. federal deficit could result in reduced demand for our products or additional pricing pressure. Further, there is ongoing uncertainty regarding the federal budget and federal spending levels, including the possible impacts of a failure to increase the “debt ceiling.” Any U.S. government default on its debt could have broad macroeconomic effects that could, among other things, raise our borrowing costs. Any future shutdown of the federal government or failure to enact annual appropriations could also have a material adverse impact on our consolidated financial condition, and results of operations. +Global market, political, environmental, and economic conditions, including those related to the financial markets, could have a material adverse effect on our operating results, financial condition, and liquidity. +Our business is sensitive to changes in general economic, political and environmental conditions, both inside and outside the U.S. Conditions such as the following, among others, may create additional risk to our results of operations: (i) continuing uncertainties in the eurozone; (ii) the effects of climate change regulation; (iii) the global effects of the ongoing COVID-19 pandemic, including the Emergency Temporary Standard (“ETS”) COVID-19 workplace vaccination and testing mandate from the Occupational Safety and Health Administration (“OSHA”); (iv) unanticipated implications from the voluntary exit of the U.K. from the EU; and (v) uncertainties in China and emerging markets. +Instability in the global economy and financial markets can adversely affect our business in several ways, including limiting our customers’ ability to obtain sufficient credit or pay for our products within the terms of sale. Competition could further intensify among the manufacturers and distributors with whom we compete for volume and market share, resulting in lower net revenue due to steeper discounts and product mix-down. In particular, if certain key or sole suppliers were to become capacity constrained or insolvent, it could result in a reduction or interruption in supplies or a significant increase in the price of supplies. +The U.K. left the EU on January 31, 2020. While all EU rules and laws continued to apply to the U.K. through the transition period, which ended December 31, 2020, the U.K. and the EU reached a free trade agreement on December 24, 2020, which was ratified on April 28, 2021 and went into effect on May 1, 2021. The agreement includes regulatory and customs cooperation mechanisms, as well as provisions supporting open and fair competition. Under the trade agreement, the U.K. is free to set its own trade policy and can negotiate with other countries that do not currently have free trade deals with the EU. Although the full impact of the trade agreement is uncertain, it is possible that the recent changes to the trading relationship between the U.K. and the EU due to the trade agreement could result in increased cost of goods imported into and exported from the U.K., which may decrease the profitability of our operations. Additional currency volatility could drive a weaker British pound, which could increase the cost of goods imported into the U.K. and may decrease the profitability of our operations. A weaker British pound versus the U.S. dollar may also cause local currency results of our operations to be translated into fewer U.S. dollars during a reporting period. Given the lack of comparable precedent, it is unclear what financial, trade, regulatory and legal implications the trade agreement will have on our business; however, Brexit and its related effects could potentially have an adverse impact on our consolidated financial condition, and results of operations. +- 22 - +Table of Contents +We depend on international net revenues, and our operating results may be adversely impacted by foreign currency, regulatory or other developments affecting international markets. +We sell products and services into approximately 70 countries. For fiscal 2022, approximately one-third of our consolidated net revenues were transacted in currencies other than the U.S. dollar. We are subject to the risks associated with fluctuations in the exchange rates for the Australian dollar, British pound, Canadian dollar, Chinese yuan, Euro, and New Israeli shekel. In addition, we have manufacturing operations, suppliers, and employees located outside the U.S. Since our growth strategy depends in part on our ability to further penetrate markets outside the U.S., we expect to continue to increase our revenue and presence outside the U.S., including in emerging markets. +Our international business is subject to risks that are often encountered in non-U.S. operations, including: +• +interruption in the transportation of materials to us and finished goods to our customers, including conditions where recovery from natural disasters may be delayed due to country-specific infrastructure and resources; +• +differences in terms of sale, including payment terms; +• +local product preferences and product requirements; +• +changes in a country’s or region’s political or economic condition, including with respect to safety and health issues; +• +trade protection measures and import or export licensing requirements; +• +unexpected changes in laws or regulatory requirements, including unfavorable changes with respect to tax, trade or sanctions compliance matters; +• +limitations on ownership and on repatriation of earnings and cash; +• +difficulty in staffing and managing widespread operations; +• +differing labor regulations; +• +difficulties in enforcing contract and property rights under local law; +• +difficulties in implementing restructuring actions on a timely or comprehensive basis; and +• +differing protection of intellectual property. +Such risks may be more likely or pronounced in emerging markets, where our operations may be subject to greater uncertainty due to increased volatility associated with the developing nature of their economic, legal, and governmental systems. +If we are unable to successfully manage the risks associated with expanding our global business or to adequately manage operational fluctuations, it could adversely affect our business, consolidated financial condition, or results of operations. +New tariffs and other trade measures could adversely affect our operating results. +The current U.S. administration has expressed strong concerns about imports from countries that it perceives as engaging in unfair trade practices, and it is possible the administration could impose import duties or other restrictions on products, components or raw materials sourced from those countries, which may include countries from which we import components or raw materials. We are currently not aware of any new import duties imposed on our products. Any such new import duties or restrictions could have a material adverse effect on our business, results of operations or financial condition. Moreover, these new tariffs, or other changes in U.S. trade policy, could trigger retaliatory actions by affected countries. Certain foreign governments have instituted or are considering imposing trade sanctions on certain U.S. goods. +Other foreign governments are considering the imposition of sanctions that will deny U.S. companies access to critical raw materials. A “trade war” of this nature or other governmental actions related to tariffs or international trade agreements or policies has the potential to adversely impact demand for our products, our costs, customers, manufacturers, suppliers and/or the economic environments in which we operate and, thus may adversely impact our businesses. In addition, there may be changes to existing trade agreements, like the North American Free Trade Agreement (“NAFTA”) and its anticipated successor agreement, the U.S.-Mexico-Canada Agreement (“USMCA”), which is still subject to approval by the U.S., Mexico and Canada, greater restrictions on free trade generally, and significant increases in tariffs on goods imported into the U.S., particularly tariffs on products manufactured in Mexico, among other possible changes. It remains unclear what the U.S. administration or foreign governments will or will not do with respect to tariffs, NAFTA, USMCA or other international trade agreements and policies. Any changes to NAFTA (or subsequent trade agreements) could impact our operations in countries where we manufacture or sell products, or source components or materials, which could adversely affect our business and results of operations. +- 23 - +Table of Contents +If product liability lawsuits are successfully brought against us, we may incur substantial liabilities and may have to limit or cease sales of our products. +The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We currently carry product liability insurance at a level we believe is commercially reasonable, although there is no assurance that it will be adequate to cover claims that may arise. In certain customer contracts, we indemnify third parties for certain product liability claims related to our products. These indemnification obligations may cause us to pay significant sums of money for claims that are covered by these indemnifications. In addition, a defect in the design or manufacture of our products could have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our results of operations. +Risks Related to Our Common Stock +The market price of our common stock may be volatile and fluctuate significantly, which could result in substantial losses for stockholders and subject us to litigation. +The market price of our common stock may be subject to significant fluctuations due to numerous factors, including but not limited to the risks described in this “Risk Factors” section. In addition, the stock market in general, the NASDAQ Global Market and the market for diagnostics companies in particular may experience a loss of investor confidence. A loss of investor confidence may result in extreme price and volume fluctuations in our common stock that are unrelated or disproportionate to the operating performance of our business, financial condition or results of operations. These broad market and industry factors may materially harm the market price of our common stock and expose us to securities class-action litigation. Class-action litigation, even if unsuccessful, could be costly to defend and divert management’s attention and resources, which could further materially harm our consolidated financial condition and results of operations. +Our business could be negatively impacted as a result of shareholder activism, an unsolicited takeover proposal or a proxy contest. +In recent years, proxy contests and other forms of stockholder activism have been directed against numerous public companies. If a proxy contest or an unsolicited takeover proposal is made with respect to us, we could incur significant costs in defending our company, which would have an adverse effect on our financial results. Shareholder activists may also seek to involve themselves in the governance, strategic direction and operations of our company. Such proposals may disrupt our business and divert the attention of our management and employees, and any perceived uncertainties as to our future direction resulting from such a situation could result in the loss of potential business opportunities, be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel and business partners, all of which could adversely affect our business. In addition, actions of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business. +The authority of our board to issue preferred stock and the effects of certain provisions of Ohio corporation law may discourage takeover bids. +Our board of directors has the authority to issue up to one million shares of undesignated preferred stock and to determine the rights, preferences, privileges and restrictions, including voting rights, of such shares without any future vote or action by the shareholders. The issuance of preferred stock under certain circumstances could have the effect of delaying or preventing a change in control of our company. Ohio corporation law contains provisions that may discourage takeover bids for our company that have not been negotiated with the board of directors. Such provisions could limit the price that investors might be willing to pay in the future for shares of our common stock. In addition, sales of substantial amounts of shares in the public market could adversely affect the market price of our common stock and our ability to raise additional capital at a price favorable to us. +- 24 - +Table of Contents +General Risk Factors +One or more cybersecurity incidents may adversely impact our financial condition, results of operations and reputation. +Our operations involve the use of multiple systems that process, store and transmit sensitive information about our customers, suppliers, employees, financial position, operating results and strategies. We face global cybersecurity risks and threats on a continual and ongoing basis, which include, but are not limited to, attempts to access systems and information, computer viruses, or denial-of-service attacks. These risks and threats range from uncoordinated individual attempts to sophisticated and targeted measures. While we are not aware of any material cyber-attacks or breaches of our systems to date, we have and continue to implement measures to safeguard our systems and information and mitigate potential risks, including employee training around phishing, malware and other cyber risks, but there is no assurance that such actions will be sufficient to prevent cyber-attacks or security breaches that manipulate or improperly use our systems, compromise sensitive information, destroy or corrupt data, or otherwise disrupt our operations. The occurrence of such events, including breaches of our security measures or those of our third-party service providers, could negatively impact our reputation and our competitive position and could result in litigation with third parties, regulatory action, loss of business due to disruption of operations and/or reputational damage, potential liability and increased remediation and protection costs, any of which could have a material adverse effect on our consolidated financial condition and results of operations. In an effort to mitigate the financial impact such an attack might have on the Company, we maintain cyber liability insurance coverage. However, such coverage may be insufficient to cover the full impact of a cyber-attack. Additionally, as cybersecurity risks become more sophisticated, we may need to increase our investments in security measures which could have a material adverse effect on our consolidated financial condition and results of operations. +Our business could be negatively affected if we are unable to attract, hire and retain key personnel. +Our future success depends on our continued ability to attract, hire and retain highly qualified personnel, including our executive officers and scientific, technical, sales and marketing employees, and their ability to manage growth successfully. If such key employees were to leave and we were unable to obtain adequate replacements, our results of operations could be adversely affected. +Our bank credit agreement imposes restrictions with respect to our operations, which could adversely impact our business. +Our bank credit agreement contains a number of financial covenants that require us to meet certain financial ratios and tests. If we fail to comply with the obligations in the credit agreement, we would be in default under the credit agreement. If an event of default is not cured or waived, it could result in acceleration of any indebtedness under our credit agreement, which could have a material adverse effect on our business. At September 30, 2022, we had $25,000 outstanding on a $200,000 bank revolving credit facility. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Our corporate offices are located in the Village of Newtown, a suburb of Cincinnati, Ohio. Our Newtown campus includes sites for diagnostic test manufacturing and distribution, immunoassay research and development and administrative functions. Our Newtown campus also includes a new facility where we are expanding and automating our Revogene diagnostic test device manufacturing. We also have diagnostic test manufacturing and distribution sites in Billerica, Massachusetts (blood-chemistry), Modi’in, Israel (BreathID and BreathTek urea breath testing systems), and Quebec City, Quebec, Canada (Revogene diagnostic test device and instrument manufacturing). Our sites in Billerica, Modi’in and Quebec City also include research and development functions. We also operate a Diagnostics sales and distribution center near Milan, Italy, and space in Manasquan, New Jersey to house BreathID technical service and repair functions. +- 25 - +Table of Contents +Our Life Science operations are conducted in several facilities in Memphis, Tennessee; Boca Raton, Florida; North Brunswick, New Jersey; London, England; Luckenwalde, Germany; Sydney, Australia; and Beijing, China. Manufacturing of molecular reagents occurs in our London and Luckenwalde sites. Manufacturing of immunoassay reagents occurs in our Memphis and Boca Raton sites. Our sites in London and North Brunswick also include our primary research and development functions. +ITEM 3. +LEGAL PROCEEDINGS +We are a party to various litigation matters that we believe are in the normal course of business, including matters related to the previously discussed pending merger. Aside from the matters discussed below, the ultimate resolution of these matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows, and no material provision has been made in the Consolidated Financial Statements for these matters. +Legal Matter Relating to LeadCare Product Line +On April 17, 2018, the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlined documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas, both to former employees of Magellan, calling for witnesses to testify before a federal grand jury related to this matter. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. It is the Company’s understanding that multiple witnesses have testified before the federal grand jury and the DOJ’s investigation is ongoing. Discussions continue with the DOJ to explore resolution of the matter. As of September 30, 2022, in accordance with applicable accounting guidance, the Company believes a loss is probable in the DOJ LeadCare legal matter and has accrued $10,000 as an estimate of the cost to resolve the DOJ LeadCare legal matter, which is reflected in litigation and select legal costs within the Consolidated Statement of Operations for the year ended September 30, 2022. The Company cannot predict when the investigation will be resolved or the outcome of the investigation, and the ultimate resolution of the DOJ LeadCare legal matter may exceed the amount accrued at September 30, 2022 and could be material to the Company. Expense for attorneys’ fees related to this matter totaling $3,510, $2,803 and $2,035 is included within the Consolidated Statements of Operations for the years ended September 30, 2022, 2021 and 2020, respectively. See “Lead Testing Matters” beginning on page 32 within MD&A. +Litigation Relating to the Merger +On September 9, 2022, a purported shareholder of the Company filed an action against the Company and the members of the Company’s board of directors in the United States District Court for the Southern District of New York, captioned Warren v. Meridian Bioscience Inc. , No. 1:22-cv-07727 (S.D.N.Y.). This was followed by four other substantively similar actions also brought by purported shareholders against the Company and the members of the Company’s board of directors. These were Stein v. Meridian Bioscience Inc. , No. 1:22-cv-07814 (S.D.N.Y.), filed on September 13, 2022; Coffman v. Meridian Bioscience Inc. , No. 1:22-cv-07984 (S.D.N.Y.), filed on September 19, 2022; Morgan v. Meridian Bioscience Inc. , No. 1:22-cv-08057 (S.D.N.Y.), filed on September 21, 2022; and Scott v. Meridian Bioscience Inc. , No. 1:22-cv-08114 (S.D.N.Y.), filed on September 22, 2022. Plaintiffs in each case generally alleged that the proxy statements filed by Meridian with the U.S. Securities and Exchange Commission on August 25, 2022 and September 8, 2022 in connection with the Merger misrepresented and/or omitted certain material information and asserted violations of Sections 14(a) and 20(a) of the Securities Exchange Act of 1934. Among other relief, the plaintiffs in each case sought injunctive relief, including directing Meridian to disclose the allegedly omitted material information, enjoining the completion of the Merger, rescinding the Merger in the event it is consummated, and awarding rescissory damages. While Meridian believed that the actions were without merit, on September 30, 2022, Meridian voluntarily filed a Form 8-K that made certain supplemental disclosures related to the Merger. Thereafter, plaintiffs in all five actions voluntarily dismissed their complaints without prejudice. +- 26 - +Table of Contents +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +PART II. +ITEM 5. +MARKET FOR REGISTRANT’S COMMON +EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock trades on the NASDAQ Global Select Market under the symbol VIVO. +Holders of our Common Stock +As of September 30, 2022, there were approximately 490 holders of record and approximately 23,850 beneficial owners of our common shares. +Dividends +During 2019, the Company suspended the payment of a quarterly cash dividend as part of the Company’s regular evaluation of its capital allocation, with the action taken in order to deploy cash into new product development activities and to preserve capital resources and liquidity for general corporate purposes. Any declaration and amount of dividends will be determined by the board of directors in its discretion based upon its evaluation of earnings, cash flow requirements, business developments and opportunities, and any other factors the board of directors determines are relevant to its evaluation. At this time, we do not expect to resume paying cash dividends. +Stock Total Return Performance +The graph below compares the cumulative 5-Year total return realized by shareholders on Meridian Bioscience, Inc.’s common stock relative to the cumulative total returns of the NASDAQ Composite index and a customized peer group comprised of the following ten companies: +Bio-Rad Laboratories, Inc., Bio-Techne Corporation, bioMerieux S.A., DiaSorin S.p.a., Hologic, Inc., Myriad Genetics, Inc., OraSure Technologies, Inc., Qiagen N.V., QuidelOrtho Corporation, and Trinity Biotech Plc. +An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock, in the index and in the peer group (including reinvestment of dividends) on September 30, 2017, and its relative performance is tracked through September 30, 2022. +- 27 - +Table of Contents +ITEM 6. +INTENTIONALLY OMITTED +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Refer to “Note About Forward-Looking Statements” following the Index in front of this Form 10-K and Item 1A “Risk Factors” on pages 12 through 25 of this Annual Report. +In the discussion that follows, all dollar amounts are in thousands (both tables and text), except per share data . +- 28 - +Table of Contents +The purpose of Management’s Discussion and Analysis is to provide an understanding of the financial condition, changes in consolidated financial condition and results of operations of Meridian Bioscience, Inc. (“Meridian”, the “Company”, “We”). This discussion should be read in conjunction with the Consolidated Financial Statements and notes. It should be noted that the terms revenue and/or revenues are utilized throughout the Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) to indicate net revenue and/or net revenues. In addition, throughout the MD&A, we refer to certain product tradenames and trademarks, which are protected under applicable intellectual property laws and are our property. Solely for convenience, these tradenames and trademarks are referred to without the ® or ™ symbols, but such references are not intended to indicate in any way that we will not assert, to the fullest extent of the law, our rights to these tradenames and trademarks. +Reportable Segments +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of manufacturing operations for infectious disease products in Cincinnati, Ohio; Quebec City, Canada; and Modi’in, Israel; and manufacturing operations for blood chemistry products in Billerica, Massachusetts (near Boston). These diagnostic test products are sold and distributed in the countries comprising North and Latin America (the “Americas”); Europe, Middle East and Africa (“EMEA”); and other countries outside of the Americas and EMEA (rest of the world, or “ROW”). The Life Science segment consists of manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; and Luckenwalde, Germany, and the sale and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, isothermal mixes, enzymes, nucleotides, and bioresearch reagents domestically and abroad, including a sales and business development facility, with outsourced distribution capabilities, in Beijing, China to further pursue growing revenue opportunities in Asia. +Recent Developments +Agreement and Plan of Merger +On July 7, 2022, the Company entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “Merger Agreement”) with SD Biosensor, Inc., a corporation with limited liability organized under the laws of the Republic of Korea (“SDB”), Columbus Holding Company, a Delaware corporation (“Parent”), and Madeira Acquisition Corp., an Ohio corporation and a direct wholly owned subsidiary of Parent (“Merger Sub”). Meridian is informed that SJL Partners, LLC (“SJL”) is currently the sole shareholder of Parent, and SDB together with SJL will be the sole shareholders of Parent as of the closing of the Merger. Pursuant to the Merger Agreement, Merger Sub will merge with and into Meridian (the “Merger”), with Meridian surviving the Merger as a direct wholly owned subsidiary of Parent. +At the effective time of the proposed Merger (the “Effective Time”), each share of common stock, no par value per share, of the Company issued and outstanding as of immediately prior to the Effective Time (other than dissenting shares or shares of the Company’s common stock held by the Company as treasury stock or owned by SDB, Merger Sub or any subsidiary of the Company or SDB) will be cancelled and cease to exist and automatically convert into the right to receive cash in an amount equal to $34.00, without interest (the “Merger Consideration”). +Consummation of the Merger is subject to customary closing conditions, including, without limitation: (i) the absence of certain legal impediments; and (ii) the condition that no Specified Outcome, as such term is defined in the Merger Agreement, related to the DOJ LeadCare legal matter (which is described in the section entitled “Legal Matter Relating to LeadCare Product Line” of Item 3. “Legal Proceedings”) has occurred or is reasonably likely to occur. +On November 21, 2022, the parties received clearance from the Committee on Foreign Investment in the United States with respect to the Merger and the transactions contemplated by the Merger Agreement. +The Merger Agreement contains certain termination rights for the Company and SDB. In addition to the foregoing termination right, and subject to certain limitations: (i) the Company or SDB may terminate the Merger Agreement if the Merger is not consummated by January 6, 2023; and (ii) the Company and SDB may mutually agree to terminate the Merger Agreement. +The foregoing description of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Merger Agreement, which is attached as an exhibit to our Current Report on Form 8-K filed with the SEC on July 7, 2022. +- 29 - +Table of Contents +The Company incurred transaction related costs of approximately $6,800 in the year ended September 30, 2022 related to the Merger, which is recorded in acquisition and transaction related costs in the Consolidated Statements of Operations. +Impact of COVID-19 Pandemic +Starting in the latter half of fiscal 2020 and continuing to the date of this filing, the ongoing COVID-19 pandemic has had both positive and negative effects on our business. +Our Life Science segment’s products were well positioned to respond to in vitro device (“IVD”) manufacturers’ increased demand for reagents used in the manufacture of molecular, rapid antigen and serology tests. Consequently, through the end of the second quarter of fiscal 2022, our Life Science segment consistently delivered significantly higher levels of net revenues and operating income than those achieved prior to the COVID-19 pandemic, with the peak to date in such levels occurring during the second quarter of fiscal 2022. This revenue peak has been followed by a significant decrease in such net revenue levels during the fiscal 2022 third and fourth quarters, reflecting the softening in demand for COVID-19 related reagents during the second half of our fiscal year. +Our Diagnostics segment, on the other hand, has generally been negatively impacted by health systems’ increased focus on COVID-19 testing over traditional infectious disease testing. The impacts of the COVID-19 pandemic are most dramatically evident in the 34% year-over-year decline in revenues from respiratory illness assays in fiscal 2021, following flat year-over-year revenue levels experienced in fiscal 2020. Reflecting what we believe to be a continuation of a return to pre-pandemic activity levels, during fiscal 2022, net revenues from our respiratory illness assays were 51% higher than fiscal 2021, a marked improvement over the aforementioned 34% decline in fiscal 2021. +Despite these recent COVID-19 pandemic related trends, due to the many uncertainties surrounding the COVID-19 pandemic, we can provide no assurances with respect to our views of the longevity or severity of the positive or negative impacts to our consolidated financial condition of the ongoing COVID-19 pandemic. +Employee Safety +While the majority of our employee base has returned to working on-site at our facilities, we have implemented a hybrid work-from-home program for certain personnel whose on-site presence has been deemed to be non-essential. We also continue to utilize enhanced cleaning and sanitizing procedures, and provide additional personal hygiene supplies at all our sites. We have implemented policies for employees to adhere to Centers for Disease Control and Prevention (“CDC”) guidelines on social distancing, and similar guidelines by authorities outside the U.S. To date, we have been able to manufacture and distribute products globally, and all our sites have continued to operate with little, if any, impact on shipments to customers. As the COVID-19 pandemic continues, along with continuing governmental restrictions which vary by locale and jurisdiction, there is an increased risk of employee absenteeism, which could materially impact our operations at one or more sites. To date, the steps we have taken, including our work-from-home processes, have not materially impacted the Company’s financial reporting systems, internal controls over financial reporting or disclosure controls. +Supply Chains +Supply chains supporting our products have generally remained intact, providing access to sufficient inventory of the key materials needed for manufacturing. While we have experienced extended lead times for certain select raw materials, delays and allocations for raw materials have to date been limited and have not had a material impact on our results of operations. From time to time, we identify alternative suppliers to address the risk of a current supplier’s inability to deliver materials in volumes sufficient to meet our manufacturing needs; or we may choose to purchase certain materials in bulk volumes where we have supply chain scarcity concerns. It remains possible that we may experience some sort of interruption to our supply chains, and such an interruption could materially affect our ability to timely manufacture and distribute our products and unfavorably impact our results of operations. +Since the second half of fiscal 2021, we have experienced input cost inflation, including materials, labor and transportation costs. Pricing actions and supply chain productivity initiatives have mitigated and are expected to continue to mitigate some of these inflationary pressures, but we may not be successful in fully offsetting these incremental costs, which could have an impact on the Company’s results of operations and cash flows in the future. +- 30 - +Table of Contents +Product Development and Clinical Trials +Our Diagnostics segment’s new product development programs are continuing to progress at a slower pace than normal, due in part to the prevalence of certain infectious diseases having been lower than normal during the COVID-19 pandemic. These matters continue to impact our timing for filing applications for product clearances with the U.S. Food and Drug Administration (“FDA”), as well as related timing of FDA clearances of such filings. Additionally, the ongoing COVID-19 pandemic has slowed and could continue to slow down our efforts to expand our product portfolio, impacting the speed with which we are able to bring additional products to market. +Product Demand +Our Life Science segment manufactures, markets and sells a number of molecular and immunological reagents to IVD customers, including those who are making both molecular and immunoassay COVID-19 tests. While there have been quarter-to-quarter fluctuations in demand throughout the COVID-19 pandemic, from late in the second quarter of fiscal 2020 through the second quarter of fiscal 2022, we generally experienced unprecedented demand for certain of our molecular reagents (e.g., ribonucleic acid (“RNA”) master mixes and nucleotides). While we expect demand to continue to exceed pre-COVID-19 pandemic levels, the significant decline in COVID-19 related demand experienced during the third and fourth quarters of fiscal 2022 is expected to continue into fiscal 2023. These expectations will certainly be impacted by infection rates and the responses to such levels of infection varying by country based on their individual COVID-19 case statistics, potential seasonality of infection rates and vaccine programs. Furthermore, a significant number of our Life Science segment customers now use our molecular reagents in multiple tests, including non-COVID-19 related tests. This development makes it increasingly difficult to accurately estimate the portion of molecular reagent sales related specifically to COVID-19. As a result, we are no longer reporting the portion of Life Science segment net revenues related to COVID-19. Such net revenues were identified and reported throughout fiscal 2021 and fiscal 2020, totaling approximately $111,900 and $71,500, respectively. +Our Diagnostics segment manufactures, markets and sells a number of molecular, immunoassay, blood chemistry and urea breath tests for various infectious diseases and blood-lead levels. Sales volumes for a number of these assays have been adversely affected by the COVID-19 pandemic over the past two fiscal years, as such assays are often used in non-critical care settings; however, we have seen indications of a return to more normal pre-pandemic levels. The COVID-19 pandemic also has depressed instrument orders and placements for our BreathID, Curian and Revogene platforms. Order activity for our Revogene platform was affected by the delay in obtaining emergency use authorization (“EUA”) for our SARS-CoV-2 assay, as customers took a “wait and see” approach throughout our entire EUA application process. We received the EUA on November 9, 2021, but did not begin to ship product at that time, as our SARS-CoV-2 assay required enhancement to detect the Omicron variants of the COVID-19 infection. We completed validation of these changes during the second quarter of fiscal 2022 and submitted the required information to the FDA. The FDA also requested the completion of additional clinical studies, which we completed and submitted. On July 28, 2022 notification was received from the FDA that it has re-authorized the EUA for the Revogene SARS-CoV-2 assay. As such, we began shipping this product in October 2022. Despite the situation encountered with our EUA application for the SARS-CoV-2 assay, and the delay in shipment due to the Omicron variant related enhancements, we proceeded with the process of increasing our capacity to produce these tests, as well as other tests on the Revogene platform, at our facilities in Quebec and Cincinnati. Specifically, we have: (i) added a second production line at our Quebec manufacturing facility; (ii) installed a production line in a leased facility near our corporate headquarters in Cincinnati; and (iii) are in the process of installing an additional production line in the Cincinnati leased facility. With a gross cost of approximately $17,700 through September 30, 2022, we expect these expansion efforts to be completed during calendar 2022 at a total gross cost of approximately $22,600, which is expected to be partially offset by the monies received under the National Institutes of Health Rapid Acceleration of Diagnostics (“RADx”) initiative grant entered into on February 1, 2021, and as amended on January 25, 2022, $2,750 of which had been received and used to offset the above gross cost as of September 30, 2022 (see Note 14, “National Institutes of Health Contracts” of the Consolidated Financial Statements for further discussion). +- 31 - +Table of Contents +Lead Testing Matters +On September 1, 2021, the Company’s wholly owned subsidiary Magellan announced the expansion of the Class I voluntary recall of its LeadCare test kits for the detection of lead in blood, which it had initiated in May 2021 after identifying an issue in certain manufactured lots of its LeadCare test kits. As a result of the identified issue, impacted test kit lots could potentially underestimate blood lead levels when processing patient blood samples. Although it was initially believed that the root cause of the issue related to the plastic containers used for the treatment reagent, additional studies have indicated that the root cause related to the third-party-sourced cardboard trays that held the treatment reagent containers. Upon correction of the identified supplier issue, shipment of product resumed during the second quarter of fiscal 2022. The Company continues to work closely with the FDA in its execution of the recall activities, which has included Magellan notifying customers and distributors affected by the recall and providing instructions for the return of impacted test kits. Of the $5,100 estimated and accrued as of September 30, 2021 to cover the estimated costs of the recall, it was estimated at September 30, 2022 that the remaining costs of the recall exceeded the amount accrued, and as a result, an adjustment was made to the product recall reserve. The effect of this adjustment is reflected in product recall costs (adjustment) within the Consolidated Statement of Operations for the year ended September 30, 2022, and results in approximately $430 of remaining accrued product recall costs reflected in the Consolidated Balance Sheet as of September 30, 2022. Anticipated recall-related costs primarily include temporary labor costs, product replacement and/or refund costs, mailing/shipping costs, attorneys’ fees and other miscellaneous costs. +As described in Item 3. “Legal Proceedings”, on April 17, 2018, the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlined documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas, both to former employees of Magellan, calling for witnesses to testify before a federal grand jury related to this matter. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. It is the Company’s understanding that multiple witnesses have testified before the federal grand jury and the DOJ’s investigation is ongoing. Discussions continue with the DOJ to explore resolution of the matter. As of September 30, 2022, in accordance with applicable accounting guidance, the Company believes a loss is probable in the DOJ LeadCare legal matter and has accrued $10,000 as an estimate of the cost to resolve the DOJ LeadCare legal matter, which is reflected in litigation and select legal costs within the Consolidated Statement of Operations for the year ended September 30, 2022. The Company cannot predict when the investigation will be resolved or the outcome of the investigation, and the ultimate resolution of the DOJ LeadCare legal matter may exceed the amount accrued at September 30, 2022 and could be material to the Company. Expense for attorneys’ fees related to this matter totaling $3,510, $2,803 and $2,035 is included within the Consolidated Statements of Operations for the years ended September 30, 2022, 2021 and 2020, respectively. +Magellan submitted 510(k) applications in December 2018, seeking to reinstate venous blood sample-types for its LeadCare II, LeadCare Plus and LeadCare Ultra testing systems. In the second fiscal quarter of 2019, the FDA informed Magellan that each of these 510(k) applications had been put on Additional Information hold. On July 15, 2019, we provided responses to the FDA’s requests for Additional Information. These 510(k) applications have since expired and are no longer under FDA review. Further, while Magellan’s LeadCare testing systems remain cleared for marketing by the FDA and permitted for use with capillary blood samples, the FDA advised that it has commissioned a third-party study of the Company’s LeadCare testing systems using both venous and capillary blood samples. According to the FDA, the results of the field study will be used in conjunction with other information to determine whether further action by the FDA or the CDC is necessary to protect the public health. The Company intends to fully cooperate with the FDA or CDC on any follow-up based on the third-party study. +- 32 - +Table of Contents +During October 2019, the FDA performed a follow-up inspection of Magellan’s manufacturing facility. The FDA issued five Form FDA 483 observations. On March 18, 2020, we participated in a regulatory meeting with the FDA at the FDA’s request to further discuss the Form FDA 483 observations and our remediation efforts. Since the inspection, we have submitted a number of written responses to the FDA regarding the five Form FDA 483 observations issued in the October 2019 inspection, and have worked diligently to execute a remediation plan. During October 2020, the FDA issued Establishment Inspection Reports which closed out the inspections from June 2017 and October 2019 under 21 C.F.R.20.64(d)(3). +During June 2021, the FDA performed an inspection of Magellan’s manufacturing facility. As a result of this inspection, the FDA issued one Form 483 observation. On August 3, 2021, FDA sent Magellan a close-out letter for the Warning Letter that FDA issued to Magellan on October 23, 2017. FDA’s close-out letter notified Magellan that FDA has completed an evaluation of Magellan’s corrective actions in response to FDA’s Warning Letter, and based on FDA’s evaluation, Magellan has addressed the issues identified in the Warning Letter. FDA’s close-out letter also stated that future FDA inspections of Magellan and regulatory activities will further assess the adequacy and sustainability of Magellan’s corrections. +Results of Operations +Fourth Quarter +Net earnings for the fourth quarter of fiscal 2022 decreased 14% to $5,705, or $0.13 per diluted share, from net earnings for the fourth quarter of fiscal 2021 of $6,657, or $0.15 per diluted share. The level of net earnings in the fourth quarter of fiscal 2022 results primarily from the decline in net revenues and operating income in our Life Science segment, stemming from the continued softening in demand for COVID-19 related reagents during the quarter. As it relates to our Life Science segment net revenues, a significant number of our Life Science segment customers now use our molecular reagents in multiple tests, including non-COVID-19 related tests. This development makes it increasingly difficult to accurately estimate the portion of molecular reagent sales related specifically to COVID-19. As a result, we are no longer reporting the portion of Life Science segment net revenues related to COVID-19. Such net revenues were identified and reported throughout fiscal 2021 and totaled approximately $23,300 in the fourth quarter of fiscal 2021. By contrast, the fourth quarter of fiscal 2021 was adversely affected by approximately $5,600, or $0.10 per diluted share, of LeadCare product recall expenses and a $4,596, or $0.08 per diluted share, upward adjustment to the fair value of acquisition consideration related to the acquisition of the business of GenePOC, Inc. (“GenePOC”) (i.e., incremental expense), offsetting the impact of higher net revenues and resulting gross profit. +Consolidated net revenues for the fourth quarter of fiscal 2022 totaled $65,675, a decrease of 14% compared to the fourth quarter of fiscal 2021. +Net revenues from the Diagnostics segment for the fourth quarter of fiscal 2022 increased 14% to $39,187, compared to the fourth quarter of fiscal 2021, comprised of a 22% increase in non-molecular assay products, partially offset by a 27% decrease in molecular assay products. Non-molecular assay product sales include the addition of sales of the BreathTek product, which was acquired July 31, 2021. The fourth quarter of fiscal 2022 represents the sixth consecutive quarter our Diagnostics segment has shown positive revenue growth versus the same quarter in the prior fiscal year. Our Diagnostics segment generated a $122 operating loss for the fourth quarter of fiscal 2022, compared to an operating loss of $11,680 in the fourth quarter of fiscal 2021, largely due to the fiscal 2021 fourth quarter including $5,600 of LeadCare product recall expenses and $4,596 upward adjustment to the fair value of acquisition consideration related to the acquisition of the business of GenePOC (i.e., incremental expense) (see Note 3, “Fair Value Measurements” of the Consolidated Financial Statements). +With a 53% decrease in net revenues from molecular reagents products and an 8% decrease in net revenues from immunological reagents products, net revenues for our Life Science segment decreased 37% to $26,488 during the fourth quarter of fiscal 2022 compared to the fourth quarter of fiscal 2021. Our Life Science segment generated $10,064 of operating income, or a margin of 38%, for the fourth quarter of fiscal 2022, a decrease of $13,118 from $23,182, or a margin of 55%, achieved in the fourth quarter of fiscal 2021, primarily due to the decrease in net revenues and associated gross profit margins, resulting in large part from the immunological reagent products representing a higher percentage of net revenues, as described in the respective sections below. +- 33 - +Table of Contents +Fiscal Year +Net earnings for fiscal 2022 decreased 41% to $42,459, or $0.96 per diluted share, from net earnings for fiscal 2021 of $71,407, or $1.62 per diluted share. The level of net earnings in fiscal 2022 reflects primarily: (i) the overall increase in operating expenses described in the Operating Expenses section below; and (ii) the decrease in gross profit margins resulting from immunological reagent products representing a higher percentage of both Life Science segment and total consolidated net revenues in the fiscal 2022 period, compared to higher margin molecular reagent products in the fiscal 2021 period. As previously noted, we are no longer reporting the portion of Life Science segment net revenues related to COVID-19, noting that such net revenues totaled approximately $111,900 in fiscal 2021. +Consolidated net revenues for fiscal 2022 totaled $333,018, an increase of 5% compared to fiscal 2021. +Diagnostics segment net revenues increased 22% to $155,903 in fiscal 2022, comprised of a 27% increase in non-molecular assay products including the addition of sales of the BreathTek product, which was acquired July 31, 2021, partially offset by a 5% decrease in molecular assay products. Our Diagnostics segment generated operating income of $2,982 in fiscal 2022, compared to an operating loss of $7,280 in fiscal 2021. This year over year improvement in operating income resulted primarily from the combined effects of: (i) the Diagnostics segment’s increase in net revenues; and (ii) fiscal 2021 including $5,600 of LeadCare product recall expenses. These factors contributing to the improvement in operating margin were partially offset by the effect of lower gross profit margins and increase in operating expenses described in the respective sections below. +With a 30% decrease in net revenues from molecular reagents products and a 43% increase in net revenues from immunological reagents products, including COVID-19 related products, net revenues for our Life Science segment decreased 7% to $177,115 during fiscal 2022 compared to fiscal 2021. Our Life Science segment generated $86,040 of operating income in fiscal 2022, a decrease of $28,974 from fiscal 2021, primarily due to the decrease in net revenues and gross profit margins, resulting from the aforementioned mix of products sold, and the increase in operating expenses, as described in the respective sections below. +REVENUE OVERVIEW +Below are analyses of the Company’s net revenues, by reportable segment, provided for each of the following: +- By Geographic Region +- By Product Platform/Type +Revenue Overview – By Reportable Segment & Geographic Region +Revenues for the Diagnostics segment, in the normal course of business, may be affected from year to year by buying patterns of major distributors and reference laboratories, seasonality and severity of seasonal diseases and outbreaks (including the ongoing COVID-19 pandemic), and foreign currency exchange rates. Revenues for the Life Science segment, in the normal course of business, may be affected from year to year by buying patterns of major IVD manufacturing customers, severity of disease outbreaks (specifically the ongoing COVID-19 pandemic), and foreign currency exchange rates. +See Note 2, “Revenue Recognition” of the Consolidated Financial Statements for detailed revenue disaggregation information. +Following is a discussion of the net revenues generated by these product platforms/types and/or disease states: +Diagnostics Segment Products +The Diagnostics segment’s overall 22% growth in net revenues during fiscal 2022 primarily results from the combined effects of the following: +• +Volume growth in the gastrointestinal product family, including the benefit of a full year of net revenues from sales of the BreathTek product, acquired in late July 2021 (total increase in gastrointestinal product revenue of 27% in fiscal 2022, including approximately $23,100 of net revenues from BreathTek); +- 34 - +Table of Contents +• +Volume growth in sales of respiratory illness products, comprised of tests for Group A Strep, Mycoplasma pneumonia, Influenza, and Pertussis, among others, reflecting an increase in the testing for these illnesses compared to fiscal 2021 in the midst of the COVID-19 pandemic (total increase in respiratory illness products of 51% in fiscal 2022); +• +Volume declines from sales of blood chemistry products due to the ongoing LeadCare product recall, which commenced in May 2021, with shipment of product resuming in the second quarter of fiscal 2022 (approximately $1,200 decrease in net revenues in fiscal 2022, compared to fiscal 2021); and +• +Ongoing pricing pressure on our H. pylori stool antigen tests, which contributed approximately $2,200 of unfavorable price variance from customers in the U.S. +Life Science Segment Products +During fiscal 2022, net revenues for the Life Science segment decreased 7% from fiscal 2021. While the level of net revenues during fiscal 2022 reflects the significant decline in demand for COVID-19 related reagents during the last half of fiscal year 2022, such level of net revenues significantly outpaced the net revenues generated in fiscal 2020 (partial pandemic) and fiscal 2019 (pre-pandemic) as follows: +Fiscal 2020 +Increased 34% in total; 17% for molecular reagents and 58% for immunological reagents +Fiscal 2019 +Increased 175% in total; 295% for molecular reagents and 108% for immunological reagents +Foreign Currency +Fluctuations in foreign currency exchange rates in fiscal 2022 compared to fiscal 2021 had an approximate $5,200 unfavorable impact on fiscal 2022 consolidated net revenues; $1,700 within the Diagnostics segment and $3,500 within the Life Science segment. This compares to year-to-year currency exchange rates having an approximate $9,200 favorable impact on consolidated net revenues in fiscal 2021; $1,300 within the Diagnostics segment and $7,900 within the Life Science segment. +Significant Customers +Revenue concentrations related to certain customers within our Diagnostics and Life Science segments are set forth in Note 15, “Reportable Segments and Major Concentration Data” of the Consolidated Financial Statements. +Gross Profit: +2022 +2021 +2022 vs. 2021 +Inc (Dec) +Gross Profit +$ +188,356 +$ +201,148 +(6 +)% +Gross Profit Margin +57 +% +63 +% +-6 points +Overall gross profit margins during fiscal 2022 have been unfavorably impacted by a decline in net revenues from our Life Science segment’s molecular reagent products, which are some of our highest margin products. During fiscal 2022, approximately 28% of consolidated net revenues related to sales of molecular reagent products, compared to approximately 41% during fiscal 2021, which included the peak of the COVID-19 pandemic. +Additionally, overall gross profit margins in fiscal 2022 have been unfavorably impacted in our Diagnostics segment by the previously discussed LeadCare product recall (see “Lead Testing Matters” above) and production capacity ramp-up costs at our Cincinnati and Quebec Revogene manufacturing facilities. +- 35 - +Table of Contents +Operating Expenses—Segment Detail and Corporate +Research & +Development +Selling & +Marketing +General & +Administrative +Other (1) +Total Operating +Expenses +Fiscal 2021: +Diagnostics +$ +21,406 +$ +21,430 +$ +24,055 +$ +5,079 +$ +71,970 +Life Science +2,505 +5,350 +13,501 +— +21,356 +Corporate +— +— +11,985 +2,803 +14,788 +Total 2021 Expenses +$ +23,911 +$ +26,780 +$ +49,541 +$ +7,882 +$ +108,114 +Fiscal 2022: +Diagnostics +$ +21,424 +$ +24,268 +$ +28,563 +$ +759 +$ +75,014 +Life Science +2,911 +7,005 +14,176 +152 +24,244 +Corporate +— +— +14,409 +20,298 +34,707 +Total 2022 Expenses +$ +24,335 +$ +31,273 +$ +57,148 +$ +21,209 +$ +133,965 +(1) +Product recall expenses are included within the Diagnostics segment’s fiscal 2021 other expenses, while the Diagnostics segment’s fiscal 2022 other expenses include an adjustment to the accrual for such product recall costs. +Operating expenses in fiscal 2022 increased $25,851 to $133,965. Major components of this increase were as follows: +• +Increased Selling & Marketing costs in both the Diagnostics and Life Science segments, primarily reflecting the effects of filling certain open positions and the easing of certain travel and meeting restrictions imposed during the prior years in connection with the COVID-19 pandemic; +• +Increased General & Administrative costs, primarily reflecting the combined effects of: (i) increased purchase accounting amortization expense; and (ii) additional investment in incentive compensation tied to the Company’s financial performance; +• +A $6,548 increase in acquisition and transaction related costs, primarily within Corporate and related to the previously discussed pending merger (see “Agreement and Plan of Merger” above); and +• +A $10,707 increase in litigation and select legal costs, reflected within Corporate and primarily related to the previously discussed LeadCare legal matter (see “Lead Testing Matters” above). +Offsetting these increases was a $5,946 total net decrease in product recall costs within our Diagnostics segment, primarily related to the LeadCare product recall initiated in fiscal 2021. +Operating Income +Operating income decreased 42% in fiscal 2022, following a 52% increase in fiscal 2021, as a result of the factors discussed above. +Other Expense +Other expense, net primarily includes: (i) interest costs on the Company’s long-term borrowings and contingent grant obligations due to the Israel Innovation Authority; (ii) grant income under the RADx initiative (fiscal 2021; see Note 14, “National Institutes of Health Contracts” of the Consolidated Financial Statements); (iii) a $935 gain on the termination of interest rate swap contracts (fiscal 2022); and (iv) net currency gains and losses. Interest costs related to the revolving credit facility with a commercial bank were $1,057 and $1,420 in fiscal 2022 and 2021, respectively. The varying levels of interest costs on the revolving credit facility reflect the following approximate levels of average debt outstanding, as detailed in Note 10, “Bank Credit Arrangements” of the Consolidated Financial Statements: (i) fiscal 2022 - $39,233; and (ii) fiscal 2021 - $56,505. +- 36 - +Table of Contents +Income Taxes +The effective rate for income taxes was 22% and 21% for fiscal 2022 and 2021, respectively. The increase in effective tax rates primarily results from the anticipated non-deductibility of the previously discussed DOJ LeadCare legal matter (see “Lead Testing Matters” above), partially offset by various tax effects associated with the Company’s currently unremitted earnings of international subsidiaries. +Impact of Inflation +To the extent feasible, we have consistently followed the practice of reviewing our prices to consider the impacts of inflation on salaries and fringe benefits for employees, the cost of purchased materials and services, and transportation costs. Inflation and changing prices did not have a material adverse impact on our gross margin, net revenues or operating income in fiscal 2022 or fiscal 2021. +Liquidity and Capital Resources: +Liquidity +Our cash flow and financing requirements are determined by analyses of operating and capital spending budgets and debt service. We have historically maintained a credit facility to augment working capital requirements and to respond quickly to acquisition opportunities. +We have an investment policy that guides the holdings of our investment portfolio, which presently consists of bank savings accounts and institutional money market funds. Our objectives in managing the investment portfolio are to: (i) preserve capital; (ii) provide sufficient liquidity to meet working capital requirements and fund strategic objectives such as acquisitions; and (iii) capture a market rate of return commensurate with market conditions and our policy’s investment eligibility criteria. As we look forward, we will continue to manage the holdings of our investment portfolio with preservation of capital being the primary objective. +We intend to continue to fund our working capital requirements from current cash flows from operating activities and cash on hand, and such sources are anticipated to be adequate to fund working capital requirements, capital expenditures and debt service during the next twelve months. However, if needed, we also have an additional source of liquidity through the amount remaining available on our $200,000 bank revolving credit facility, which totaled $175,000 as of September 30, 2022. The Company also maintains a shelf registration statement on file with the SEC. Our liquidity needs may change if overall economic conditions worsen and/or liquidity and credit within the financial markets tightens for an extended period, and such conditions impact the collectability of our customer accounts receivable, impact credit terms with our vendors, or disrupt the supply of raw materials and services. +As of September 30, 2022, our cash and cash equivalents balance was $81,453, an increase of $31,682 compared to September 30, 2021. This net increase primarily results from the combined net effects of: (i) generating $82,361 of cash flow from operations, an increase of 23% over fiscal 2021; (ii) using cash to pay down $35,000 on the revolving credit facility; (iii) using cash to acquire property, plant and equipment ($7,365 net of RADx grant monies received); and (iv) acquiring EUPROTEIN, Inc. ($3,750) (see Note 4, “Business Combinations” of the Consolidated Financial Statements). In addition, the net balance of cash and cash equivalents was reduced by approximately $5,300 as of September 30, 2022, as a result of the movement in foreign currency exchange rates, specifically the British pound and Euro, since September 30, 2021. +Considering these factors, our balance of cash and cash equivalents on hand exceeded our total debt (defined as bank debt, government grant obligations and obligations related to acquisitions) by approximately $49,700 at September 30, 2022. +Capital Resources +As described in Note 10, “Bank Credit Arrangements” of the Consolidated Financial Statements, the Company maintains a $200,000 credit facility, which is secured by substantially all our U.S. assets and includes certain restrictive financial covenants. As of September 30, 2022, the Company was in compliance with all covenants. The Company also maintains a shelf registration statement on file with the SEC. +- 37 - +Table of Contents +Our capital expenditures totaled $8,615 for fiscal 2022, $1,250 of which was offset by receipts under the RADx grant initiative (see Note 14, “National Institutes of Health Contracts” of the Consolidated Financial Statements), and which largely related to expanding manufacturing capacity. During fiscal 2023, our capital expenditures are estimated to total approximately $10,000, comprised of approximately $6,500 and $3,500 in the Diagnostics and Life Science segments, respectively. Such expenditures may be funded with cash and cash equivalents on hand, operating cash flows, and/or availability under the $200,000 revolving credit facility discussed above. +Contractual Obligations: +Among the Company’s contractual obligations as of September 30, 2022 were the following (reflected along with the Note to the Consolidated Financial Statements in which the obligation is detailed): +(i) +operating leases (Note 9, “ Leasing Arrangements ” ) +(ii) +the revolving credit facility (Note 10, “ Bank Credit Arrangements ” ) +(iii) +uncertain income tax positions (Note 11, “Income Taxes” ) +(iv) +contingent government grant obligations (Note 13, “Contingent Obligations and Non-Current Liabilities” ) +The Company’s additional contractual obligations and their related due dates were as follows as of September 30, 2022: +Total +Less than 1 +Year +1-3 Years +4-5 Years +More than +5 Years +Purchase obligations (1) +$ +41,291 +$ +40,182 +$ +1,104 +$ +5 +$ +— +Acquisition price holdback (2) +1,500 +1,000 +500 +— +— +Total +$ +42,791 +$ +41,182 +$ +1,604 +$ +5 +$ +— +(1) +Purchase obligations relate primarily to outstanding purchase orders for machinery and equipment, inventory, including instruments, service items, and research and development activities. These contractual commitments are not in excess of expected production requirements over the next twelve months. +(2) +Pursuant to the purchase agreements related to the April 30, 2022 and July 31, 2021 acquisitions of EUPROTEIN Inc. and BreathTek, respectively, Meridian’s remaining consideration to be paid is comprised solely of purchase price holdbacks totaling $500 for EUPROTEIN Inc. and $1,000 for BreathTek. +Other Commitments and Off-Balance Sheet Arrangements : +License Agreements +Meridian has entered into various license agreements that require payment of royalties based on a specified percentage of sales of related products, with such percentages generally ranging from approximately 3% to 10%. During fiscal 2022, royalty expense totaled approximately $2,300, with 40% and 60% of such expense relating to our Diagnostics and Life Science segments, respectively. This compares to a total of approximately $5,200 of royalty expense in fiscal 2021, with 25% and 75% relating to our Diagnostics and Life Science segments, respectively. Meridian expects that payments under these agreements will amount to approximately $700 in fiscal 2023, with the decrease from fiscal 2022 largely resulting from the last of the licensed patents applicable to the Alethia product line having expired during fiscal 2022. +Off-Balance Sheet Arrangements +We utilize foreign currency exchange forward contracts to limit exposure to volatility in foreign currency gains and losses related to financial assets denominated in other than the holding subsidiary’s functional currency. These contracts are generally settled within a 30-day time frame and are not formally designated or accounted for as accounting hedges. We also utilize interest rate swap agreements to limit exposure to volatility in the LIBOR interest rate in connection with the revolving credit facility. The interest rate swap agreements are designated and accounted for as accounting hedges (see Note 3, “Fair Value Measurements” of the Consolidated Financial Statements). Aside from these instruments, we do not utilize special-purpose financing vehicles or have any material undisclosed off-balance sheet arrangements. +- 38 - +Table of Contents +Market Risk Exposure: +Foreign Currency Risk +We have market risk exposure related to foreign currency transactions from our operations outside the U.S., as well as certain suppliers to our domestic businesses located outside the U.S. The foreign currencies where we have market risk exposure are the Australian dollar, British pound, Canadian dollar, Chinese yuan, Euro, and New Israeli shekel. Assessing foreign currency exposures is a component of our overall ongoing risk management process, with such currency risks managed as we deem appropriate. +Concentration of Customers/Products Risk +Our Diagnostics segment’s net revenues from sales to three customers were 29% and 33% of the Diagnostics segment’s total net revenues for fiscal 2022 and 2021, respectively, or 13% of consolidated net revenues in each fiscal year. Additionally, our three major Diagnostics segment product families – gastrointestinal, respiratory illnesses and blood chemistry – accounted for 82% and 80% of our Diagnostics segment’s net revenues during fiscal 2022 and 2021, respectively, or 39% and 32% of each year’s consolidated net revenues. +Our Life Science segment’s net revenues from sales to three diagnostics manufacturing customers were 31% and 20% of the Life Science segment’s total net revenues for fiscal 2022 and 2021, respectively, or 17% and 12% of consolidated net revenues in each fiscal year. +Critical Accounting Policies: +The Consolidated Financial Statements included in this Form 10-K have been prepared in accordance with U.S. generally accepted accounting principles. Such accounting principles require management to make judgments about estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Listed below are the accounting policies management believes to be critical to understanding the Consolidated Financial Statements, along with reference to location of the policy discussion within the Consolidated Financial Statements. The listed policies are considered critical due to the fact that application of such polices requires the use of significant estimates and assumptions, and the carrying values of related assets and liabilities are material. +Accounting Policy +Location +Within Consolidated +Financial Statements +Examples of Key Estimate Assumptions +DOJ LeadCare Legal Matter +Note 5 +Estimate of loss contingency +Revenue Recognition +Note 1(i) +Distributor price adjustments and fee accruals +Income Taxes +Note 1(l) and Note 11 +Uncertain positions and state apportionment factors +Recent Accounting Pronouncements: +A description of accounting pronouncements recently adopted by the Company, as well as accounting pronouncements issued but not yet adopted by the Company, are set forth in Note 1(s), “Summary of Significant Accounting Policies- Recent Accounting Pronouncements” of the Consolidated Financial Statements. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +See Capital Resources and Market Risk Exposure above within Item 7, beginning on page 37. +- 39 - +Table of Contents +http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements +Management’s Report on Internal Control over Financial Reporting +41 +Reports of Independent Registered Public Accounting Firms (PCAOB ID # 42 for the years ended September 30, 2022 and 2021) (PCAOB ID # 248 for the year ended September 30, 2020 ) +42 +Consolidated Statements of Operations for the years ended September 30, 2022, 2021 and 2020 +46 +Consolidated Statements of Comprehensive Income for the years ended September 30, 2022, 2021 and 2020 +47 +Consolidated Statements of Cash Flows for the years ended September 30, 2022, 2021 and 2020 +48 +Consolidated Balance Sheets as of September 30, 2022 and 2021 +49 +Consolidated Statements of Shareholders’ Equity for the years ended September 30, 2022, 2021 and 2020 +51 +Notes to Consolidated Financial Statements +52 +Schedule No. II – Valuation and Qualifying Accounts for the years ended September 30, 2022, 2021 and 2020 +79 +All other supplemental schedules are omitted due to the absence of conditions under which they are required or because the information is shown in the Consolidated Financial Statements or Notes thereto. +- 40 - +Table of Contents +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). +The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of September 30, 2022, based on the framework and criteria in the 2013 +Internal Control – Integrated Framework, +issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on management’s evaluation and those criteria, the Company concluded that its system of internal control over financial reporting was effective as of September 30, 2022. +The Company’s independent registered public accounting firm has issued an attestation report on the registrant’s internal control over financial reporting. +/s/ Jack Kenny +/s/ Andrew S. Kitzmiller +Jack Kenny +Andrew S. Kitzmiller +Chief Executive Officer +Executive Vice President and +November 22, 2022 +Chief Financial Officer +November 22, 2022 +- 41 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Shareholders and the Board of Directors of Meridian Bioscience, Inc. +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheets of Meridian Bioscience, Inc. (the Company) as of September 30, 2022 and 2021, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for years then ended, and the related notes and consolidated financial statement schedule listed in the Index to Annual Report on Form 10-K at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2022 and 2021, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 22, 2022, expressed an unqualified opinion thereon. +Basis for Opinion +These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates. +LeadCare legal matter +Description of the Matters +As discussed in Note 5, at September 30, 2022, the Company has accrued $10.0 million as an estimate of the cost to settle the LeadCare legal matter with the U.S. Department of Justice (“DOJ”). As background, the Company’s wholly owned subsidiary Magellan Biosciences, Inc. (Magellan) received a subpoena from the DOJ regarding its LeadCare product line. The subpoena outlined documents to be produced, and the Company is and has been cooperating with the DOJ’s investigation in this matter and discussions continue with the DOJ to explore resolution of the matter. As of September 30, 2022, the Company believes it is probable that it had incurred a loss related to the resolution of the LeadCare legal matter and has accrued for its estimate of the cost to settle the LeadCare legal matter with the DOJ. +- 42 - +Table of Contents +Auditing management’s accounting for and disclosure of the estimated loss contingency from the LeadCare legal matter is especially challenging as evaluating the probability and amount of loss is subjective and requires judgment due in part to the uncertain nature of when the LeadCare legal matter will be resolved or the outcome of the investigation, and the ultimate resolution of the LeadCare legal matter. +How We Addressed the Matter in Our Audit +We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the identification, evaluation and disclosure of loss contingencies, including the Company’s assessment and measurement of the estimate of the probable cost and liability. +To test the assessment of the probability of incurrence of a loss and the estimated loss, to the extent it was reasonably estimable, we performed audit procedures that included, among others, reviewing related correspondence with external legal counsel and the DOJ, reviewing legal counsel confirmation letters, assessing scope and cost estimates the Company used in determination for its estimate of the cost to settle the LeadCare legal matter, and searching for other available information that might indicate new or contrary facts related to the matter. +/s/ Ernst & Young LLP +We have served as the Company’s auditor since 2020. +Cincinnati, Ohio +November 22, 2022 +- 43 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +Board of Directors and Shareholders +Meridian Bioscience, Inc. +Opinion on the financial statements +We have audited the consolidated balance sheet of Meridian Bioscience, Inc. (an Ohio corporation) and subsidiaries (the “Company”) as of September 30, 2020 (not presented herein), and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for the year then ended and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2020, and the results of its operations and its cash flows for the year ended September 30, 2020, in conformity with accounting principles generally accepted in the United States of America. +Basis for opinion +These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. +/s/ GRANT THORNTON LLP +We served as the Company’s auditor from 2005 to 2020. +Cincinnati, Ohio +November 23, 2020 +- 44 - +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Shareholders and the Board of Directors of Meridian Bioscience, Inc. +Opinion on Internal Control Over Financial Reporting +We have audited Meridian Bioscience, Inc.’s (the Company) internal control over financial reporting as of September 30, 2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2022, based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of September 30, 2022 and 2021, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for years then ended, and the related notes and consolidated financial statement schedule listed in the Index to Annual Report on Form 10-K at Item 15 and our report dated November 22, 2022, expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. +Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ Ernst & Young LLP +Cincinnati, Ohio +November 22, 2022 +- 45 - +Table of Contents +CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2022 +2021 +2020 +Net Revenues +$ +333,018 +$ +317,896 +$ +253,667 +Cost of Sales +144,662 +116,748 +97,419 +Gross Profit +188,356 +201,148 +156,248 +Operating Expenses: +Research and development +24,335 +23,911 +23,729 +Selling and marketing +31,273 +26,780 +26,486 +General and administrative +57,148 +49,541 +44,345 +Product recall costs (adjustment) +( 350 +) +5,596 +— +Acquisition and transaction related costs +6,940 +392 +3,890 +Litigation and select legal costs +13,510 +2,803 +2,080 +Restructuring costs +1,109 +— +687 +Change in fair value of acquisition consideration and settlement +— +( 909 +) +( 6,293 +) +Total Operating Expenses +133,965 +108,114 +94,924 +Operating Income +54,391 +93,034 +61,324 +Other Income (Expense): +Interest income +17 +— +142 +Interest expense +( 1,189 +) +( 1,878 +) +( 2,632 +) +RADx grant income +— +1,000 +— +Other, net +1,098 +( 1,705 +) +459 +Total Other Expense, Net +( 74 +) +( 2,583 +) +( 2,031 +) +Earnings Before Income Taxes +54,317 +90,451 +59,293 +Income Tax Provision +11,858 +19,044 +13,107 +Net Earnings +$ +42,459 +$ +71,407 +$ +46,186 +Earnings Per Share Data: +Basic earnings per common share +$ +0.97 +$ +1.65 +$ +1.08 +Diluted earnings per common share +$ +0.96 +$ +1.62 +$ +1.07 +Common shares used for basic earnings per common share +43,583 +43,259 +42,855 +Effect of dilutive stock options and restricted share units +792 +753 +319 +Common shares used for diluted earnings per common share +44,375 +44,012 +43,174 +Anti-Dilutive Securities: +Common share options and restricted share units +154 +203 +893 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- +46 +- +Table of Contents +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2022 +2021 +2020 +Net Earnings +$ +42,459 +$ +71,407 +$ +46,186 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +( 11,929 +) +1,780 +3,884 +Recognition of gains on cash flow hedges +( 935 +) +( 154 +) +( 308 +) +Unrealized gain (loss) on cash flow hedge +2,560 +510 +( 713 +) +Income taxes related to items of other comprehensive income (loss) +( 398 +) +( 78 +) +252 +Other Comprehensive Income (Loss), Net of Tax +( 10,702 +) +2,058 +3,115 +Comprehensive Income +$ +31,757 +$ +73,465 +$ +49,301 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- 4 +7 +- +Table of Contents +CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +For the Year Ended September 30, +2022 +2021 +2020 +Cash Flows From Operating Activities +Net earnings +$ +42,459 +$ +71,407 +$ +46,186 +Non-cash items included in net earnings: +Depreciation of property, plant and equipment +6,599 +6,510 +5,823 +Amortization of intangible assets +9,912 +8,776 +7,744 +Stock compensation expense +6,900 +4,156 +3,802 +Deferred income taxes +( 1,101 +) +( 3,835 +) +760 +Estimated litigation costs +10,000 +— +— +Change in fair value of acquisition consideration and settlement +— +( 909 +) +( 6,293 +) +Change in the following, net of acquisitions: +Accounts receivable +4,564 +( 12,766 +) +( 971 +) +Inventories +5,223 +( 7,800 +) +( 18,977 +) +Prepaid expenses and other current assets +( 1,553 +) +( 3,711 +) +( 153 +) +Accounts payable and accrued expenses +1,038 +6,346 +7,248 +Income taxes payable +565 +( 329 +) +1,435 +Other, net +( 2,245 +) +( 980 +) +1,372 +Net cash provided by operating activities +82,361 +66,865 +47,976 +Cash Flows From Investing Activities +Purchase of property, plant and equipment +( 8,615 +) +( 18,312 +) +( 3,299 +) +RADx grant proceeds offsetting cost of equipment +1,250 +1,500 +— +Acquisitions, net of cash acquired and holdback +( 3,750 +) +( 18,585 +) +( 51,299 +) +Payment of acquisition consideration holdback +— +( 5,000 +) +— +Net cash used in investing activities +( 11,115 +) +( 40,397 +) +( 54,598 +) +Cash Flows From Financing Activities +Payment on revolving credit facility +( 35,000 +) +( 18,824 +) +( 57,000 +) +Proceeds from revolving credit facility +— +10,000 +50,000 +Payment of acquisition consideration +— +( 20,000 +) +— +Payment on government grant obligations +— +( 5,297 +) +— +Payment of debt issuance costs +( 404 +) +— +( 116 +) +Proceeds from exercise of stock options +2,450 +3,052 +3,559 +Employee taxes paid upon stock option exercises and net share settlement of restricted share units +( 1,349 +) +— +— +Net cash used in financing activities +( 34,303 +) +( 31,069 +) +( 3,557 +) +Effect of Exchange Rate Changes on Cash and Cash Equivalents +( 5,261 +) +858 +1,296 +Net Increase (Decrease) in Cash and Cash Equivalents +31,682 +( 3,743 +) +( 8,883 +) +Cash and Cash Equivalents at Beginning of Period +49,771 +53,514 +62,397 +Cash and Cash Equivalents at End of Period +$ +81,453 +$ +49,771 +$ +53,514 +Supplemental Consolidated Cash Flow Information: +See Notes 1(g), 3, 9, 10 and 11. +The accompanying notes are an integral part of these Consolidated Financial Statements. +- +48 +- +Table of Contents +CONSOLIDATED BALANCE SHEETS (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2022 +2021 +Assets +Current Assets: +Cash and cash equivalents +$ +81,453 +$ +49,771 +Accounts receivable, less allowances of $ 1,325 and $ 1,078 , respectively +47,235 +53,568 +Inventories, net +67,814 +76,842 +Prepaid expenses and other current assets +14,095 +12,626 +Total Current Assets +210,597 +192,807 +Property, Plant and Equipment: +Land +968 +989 +Buildings and improvements +32,983 +32,765 +Machinery, equipment and furniture +79,517 +78,410 +Construction in progress +10,589 +9,991 +Subtotal +124,057 +122,155 +Less: accumulated depreciation and amortization +79,199 +78,941 +Net Property, Plant and Equipment +44,858 +43,214 +Other Assets: +Goodwill +116,302 +114,668 +Other intangible assets, net +74,131 +84,151 +Right-of-use assets, net +5,850 +5,786 +Deferred income taxes +9,278 +8,731 +Other assets +2,081 +365 +Total Other Assets +207,642 +213,701 +Total Assets +$ +463,097 +$ +449,722 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- +49 +- +Table of Contents +CONSOLIDATED BALANCE SHEETS (in thousands) +Meridian Bioscience, Inc. and Subsidiaries +As of September 30, +2022 +2021 +Liabilities and Shareholders’ Equity +Current Liabilities: +Accounts payable +$ +17,759 +$ +11,701 +Accrued employee compensation costs +17,682 +16,853 +Accrued estimated litigation costs +10,000 +— +Accrued product recall costs +1,157 +5,100 +Current operating lease obligations +1,830 +1,990 +Current government grant obligations +667 +638 +Other accrued expenses +5,048 +7,027 +Income taxes payable +3,808 +3,848 +Total Current Liabilities +57,951 +47,157 +Non-Current Liabilities: +Post-employment benefits +1,673 +2,253 +Long-term operating lease obligations +4,127 +3,932 +Long-term debt +25,000 +60,000 +Government grant obligations +4,620 +5,176 +Long-term income taxes payable +395 +469 +Deferred income taxes +578 +1,055 +Other non-current liabilities +692 +1,378 +Total Non-Current Liabilities +37,085 +74,263 +Commitments and Contingencies +Shareholders’ Equity: +Preferred stock, no par value; 1,000,000 shares authorized; no ne issued +— +— +Common shares, no par value; 71,000,000 shares authorized, 43,755,188 and 43,361,898 issued, respectively +— +— +Additional paid-in capital +155,664 +147,403 +Treasury stock, at cost, 9,655 shares +( 259 +) +— +Retained earnings +223,160 +180,701 +Accumulated other comprehensive income (loss) +( 10,504 +) +198 +Total Shareholders’ Equity +368,061 +328,302 +Total Liabilities and Shareholders’ Equity +$ +463,097 +$ +449,722 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- +50 +- +Table of Contents +CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (in thousands, except per share data) +Meridian Bioscience, Inc. and Subsidiaries +Common +Shares +Additional +Paid-In +Capital +Treasury Stock +Retained +Earnings +Accumulated +Other Comp. +Income (Loss) +Total +Shareholders’ +Equity +Sh. +Amt. +Balance at September 30, 2019 +42,712 +$ +132,834 +— +$ +— +$ +63,108 +$ +( 4,975 +) +$ +190,967 +Conversion of restricted share units and exercise of stock options +357 +3,559 +— +— +— +— +3,559 +Stock compensation expense +— +3,802 +— +— +— +— +3,802 +Net earnings +— +— +— +— +46,186 +— +46,186 +Foreign currency translation adjustment +— +— +— +— +— +3,884 +3,884 +Hedging activity, net of tax +— +— +— +— +— +( 769 +) +( 769 +) +Balance at September 30, 2020 +43,069 +$ +140,195 +— +$ +— +$ +109,294 +$ +( 1,860 +) +$ +247,629 +Conversion of restricted share units and exercise of stock options +293 +3,052 +— +— +— +— +3,052 +Stock compensation expense +— +4,156 +— +— +— +— +4,156 +Net earnings +— +— +— +— +71,407 +— +71,407 +Foreign currency translation adjustment +— +— +— +— +— +1,780 +1,780 +Hedging activity, net of tax +— +— +— +— +— +278 +278 +Balance at September 30, 2021 +43,362 +$ +147,403 +— +$ +— +$ +180,701 +$ +198 +$ +328,302 +Conversion of restricted share units and exercise of stock options +393 +1,361 +( 10 +) +( 259 +) +— +— +1,102 +Stock compensation expense +— +6,900 +— +— +— +— +6,900 +Net earnings +— +— +— +— +42,459 +— +42,459 +Foreign currency translation adjustment +— +— +— +— +— +( 11,929 +) +( 11,929 +) +Hedging activity, net of tax +— +— +— +— +— +1,227 +1,227 +Balance at September 30, 2022 +43,755 +$ +155,664 +( 10 +) +$ +( 259 +) +$ +223,160 +$ +( 10,504 +) +$ +368,061 +The accompanying notes are an integral part of these Consolidated Financial Statements. +- +51 +- +Table of Contents +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +Meridian Bioscience, Inc. and Subsidiaries +(in thousands, except per share data) +(1) +Summary of Significant Accounting Policies +(a) +Business Description +- Meridian is a fully-integrated life science company whose principal businesses are: (i) the development, manufacture, sale and distribution of diagnostic testing systems and kits, primarily for certain gastrointestinal and respiratory infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, isothermal mixes, enzymes, nucleotides, and bioresearch reagents used by other diagnostic manufacturers and researchers. +Our reportable segments are Diagnostics and Life Science. The Diagnostics segment consists of: (i) manufacturing operations for infectious disease products in Cincinnati, Ohio; Quebec City, Canada; and Modi’in, Israel; (ii) manufacturing operations for blood chemistry products in Billerica, Massachusetts (near Boston); and (iii) the sale and distribution of diagnostics products domestically and abroad. This segment’s products are used by hospitals, reference labs and physician offices to detect infectious diseases and elevated lead levels in blood. +The Life Science segment consists of: (i) manufacturing operations in Memphis, Tennessee; Boca Raton, Florida; London, England; and Luckenwalde, Germany; and (ii) the sale and distribution of bulk antigens, antibodies, PCR/qPCR reagents, isothermal reagents, nucleotides, and bioresearch reagents domestically and abroad, including a sales and business development facility, with outsourced distribution capabilities, in Beijing, China. This segment’s products are used by manufacturers and researchers in a variety of applications (e.g., in vitro medical device manufacturing, microRNA detection, next-generation sequencing, plant genotyping, and mutation detection, among others). +(b) +Principles of Consolidation and Basis of Presentation - +The Consolidated Financial Statements include the accounts of Meridian Bioscience, Inc. and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Unless the context requires otherwise, references to “Meridian,” “we,” “us,” “our” or “our company” refer to Meridian Bioscience, Inc. and its subsidiaries. +It should be noted that the terms revenue and/or revenues are utilized throughout these notes to the Consolidated Financial Statements to indicate net revenue and/or net revenues. +(c) +Use of Estimates - +The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of net revenues and expenses during the reporting period. The Company’s results are affected by economic, political, legislative, regulatory and legal actions. Economic conditions, such as recessionary trends, inflation, supply chain disruptions, interest and monetary exchange rates, government fiscal policies, government policies surrounding the containment of the ongoing COVID-19 pandemic, and changes in prices of raw materials, can have a significant effect on the results of operations. Actual results could differ from the Company’s estimates. +(d) +Foreign Currency Translation +- Assets and liabilities of foreign operations are translated using year-end exchange rates with gains or losses resulting from translation included as a separate component of accumulated other comprehensive income (loss). Net revenues and expenses are translated using exchange rates prevailing during the year. We also recognize foreign currency transaction gains and losses on certain assets and liabilities that are denominated in the Australian dollar, British pound, Canadian dollar, Chinese yuan, Euro, and New Israeli shekel currencies. These gains and losses are included in other expense, net in the Consolidated Statements of Operations. +- +52 +- +Table of Contents +(e) +Cash and Cash Equivalents +- We consider short-term investments with original maturities of 90 days or less to be cash equivalents, including institutional money market funds. At times our investments of cash and cash equivalents with various high credit quality financial institutions may be in excess of the Federal Deposit Insurance Corporation (“FDIC”) insurance limit. +(f) +Inventories +- Inventories are stated at the lower of cost or net realizable value. Cost is determined on a first-in, first-out (“FIFO”) basis. Diagnostic testing instruments are carried in inventory until they are sold outright or placed with a customer under the customer reagent rental program, at which time they are transferred to property, plant and equipment. +We establish reserves against cost for excess and obsolete materials, finished goods whose shelf life may expire before sale to customers, and other identified exposures. The Company specifically considered the impact of the ongoing COVID-19 pandemic, specifically the demand for COVID-19 related products, on its inventories at September 30, 2022 and 2021. Such reserves were $ 6,132 and $ 4,997 at September 30, 2022 and 2021, respectively. We estimate these reserves based on assumptions about future demand and market conditions. If actual demand and market conditions were to be less favorable than such estimates, additional inventory write-downs would be required and recorded in the period known. +(g) +Property, Plant and Equipment +- Property, plant and equipment are stated at cost. Upon retirement or other disposition, the cost and related accumulated depreciation are removed from the accounts and the resulting gain or loss is reflected in net earnings. Maintenance and repairs are expensed as incurred. Depreciation is computed on the straight-line method in amounts sufficient to write-off the cost over the estimated useful lives, generally as follows: +Buildings and improvements - 18 to 40 years +Leasehold improvements - life of the lease +Machinery, equipment and furniture - 3 to 10 years +Computer equipment and software - 3 to 5 years +Instruments under customer reagent rental arrangements - 5 years +Supplemental Cash Flow Information (Non-Cash Capital Expenditures) +Additions to property, plant and equipment for which cash remained unpaid totaled $ 793 , $ 416 and $ 236 at September 30, 2022, 2021 and 2020, respectively. +(h) +Intangible Assets +- Goodwill is subject to an annual impairment review (or more frequently if impairment indicators arise) at the reporting unit level, which is performed as of the first day of the fourth fiscal quarter (July 1). +At both September 30, 2022 and 2021, we had two reporting units (Diagnostics and Life Science), both of which contained goodwill. We review our reporting unit structure annually, or more frequently if facts and circumstances warrant. Goodwill is considered impaired if the carrying value of the reporting unit exceeds its fair value. We have no intangible assets with indefinite lives other than goodwill. +During fiscal 2022, the annual impairment review of the Company’s goodwill consisted of qualitative assessments for each of our Diagnostics and Life Science reporting units. A qualitative assessment is first performed to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value using qualitative indicators. In the event that the reporting unit does not pass the qualitative assessment, the reporting unit’s carrying value is compared to its fair value, with fair value of the reporting unit estimated using market value and discounted cash flow approaches. Both our Diagnostics and Life Science reporting units satisfied the qualitative assessments as of July 1, 2022, and no impairment was recognized. +The annual goodwill impairment assessment of the Company’s goodwill as of July 1, 2021, consisted of quantitative assessments for each of our Diagnostics and Life Science reporting units. The quantitative assessments determined fair value via both market (comparable company) and income (discounted cash flows) approaches. Based upon these approaches, the fair value of each reporting unit exceeded its carrying value; therefore, each of the Diagnostics and Life Science reporting units satisfied the quantitative assessment at July +1, 2021. The impact of the ongoing COVID-19 pandemic has had varying impacts on the Diagnostics and Life Science reporting units, and specifically an adverse impact on the Diagnostics reporting unit. However, even in light of the COVID-19 pandemic, the estimated fair value of the Diagnostics reporting unit, as calculated at July 1, 2021, was over 50 % greater than its carrying value. +- +53 +- +Table of Contents +Long-lived assets, excluding goodwill, are reviewed for impairment when events or circumstances indicate that such assets may not be recoverable at their carrying value. Whether an event or circumstance triggers an impairment is determined by comparing an estimate of the asset’s future undiscounted cash flows to its carrying value. If impairment has occurred, it is measured by a fair-value based calculation. +Our ability to recover the carrying value of our identifiable intangible assets is dependent upon the future cash flows of the related assets. We make judgments and assumptions regarding future cash flows, including net revenues levels, gross profit margins, operating expense levels, working capital levels, and capital expenditures. With respect to identifiable intangible assets and fixed assets, we also make judgments and assumptions regarding useful lives. +We consider the following factors in evaluating events and circumstances for possible impairment: (i) significant under-performance relative to historical or projected operating results; (ii) negative industry trends; (iii) net revenues levels of specific groups of products (related to specific identifiable intangibles); (iv) changes in overall business strategies; and (v) other factors. If actual cash flows are less favorable than projections, this could trigger impairment of identifiable intangible assets and other long-lived assets. No triggering events have been identified by the Company for the years ended September 30, 2022, 2021 and 2020. +(i) +Revenue Recognition and Accounts Receivable +- +Revenue Recognition Policies +Product Sales +Revenue from contracts with customers is recognized in an amount that reflects the consideration we expect to receive in exchange for products when obligations under such contracts are satisfied. Revenue is generally recognized at a point-in-time when products are shipped, and control has passed to the customer. Such contracts can include various combinations of products that are generally accounted for as distinct performance obligations. +Revenue is reduced in the period of sale for fees paid to distributors, which are inseparable from the distributor’s purchase of our product and for which we receive no goods or services in return. Revenue is reduced at the date of sale for product price adjustments payable to certain distributors under local contracts. Management estimates accruals for distributor price adjustments based on local contract terms, sales data provided by distributors, historical statistics, current trends, and other factors. Changes to the accruals are recorded in the period that they become known. Such accruals are netted against accounts receivable. +Shipping and handling costs incurred after control of the product is transferred to our customers are treated as fulfillment costs and not a separate performance obligation. +Our payment terms differ by jurisdiction and customer, but payment is generally required in a term ranging from 30 to 90 days from the date of shipment or satisfaction of the performance obligation . Accounts receivable are recorded in the Consolidated Balance Sheets at invoiced amounts less provisions for distributor price adjustments under local contracts and doubtful accounts. The allowance for doubtful accounts represents our estimate of probable credit losses and is based on historical write-off experience and known conditions that would likely lead to non-payment. Customer invoices are charged off against the allowance for doubtful accounts when we believe it is probable that the invoices will not be paid. The Company specifically considered the impact of the ongoing COVID-19 pandemic on its accounts receivable and determined there was no material impact on existing accounts receivable at September 30, 2022 or 2021. +Practical Expedients and Exemptions +Revenue is recognized net of any taxes collected from customers (sales tax, value added tax, etc.), which are subsequently remitted to government authorities. +- +54 +- +Table of Contents +Our diagnostic assay products are generally not subject to a customer right of return except for product recall events under the rules and regulations of the U.S. Food and Drug Administration (“FDA”) or equivalent agencies outside the U.S. In this circumstance, the costs to replace or refund affected products would be accrued at the time a loss was probable and estimable. +We expense as incurred the costs to obtain contracts, as the amortization period would be one year or less. These costs, recorded within selling and marketing expense, include our internal sales force compensation programs and certain partner sales incentive programs, as we have determined that annual compensation is commensurate with annual selling activities. +Reagent Rental Arrangements +Certain of our Diagnostics segment’s product platforms require the use of instruments for the tests to be processed. In many cases, a customer is given use of the instrument provided they continue purchasing the associated tests, also referred to as “consumables” or “reagents.” If a customer stops purchasing the consumables, the instrument must be returned to us. Such arrangements are common practice in the diagnostics industry and are referred to as “Reagent Rentals.” Reagent Rentals may also include instrument related services such as a limited replacement warranty, training and installation. We concluded that the use of the instrument and related services (collectively known as “lease elements”) are not within the scope of Accounting Standards Codification (“ASC”) 606, +Revenue from Contracts with Customers +but rather ASC 842, +Leases +. Accordingly, we first allocate the transaction price between the lease elements and the non-lease elements based on estimates of relative standalone selling prices. Lease revenue is derived solely from the sale of consumables and is therefore recognized monthly as earned, which coincides with the transfer of control of the non-lease elements. +For the portion of the transaction price allocated to the non-lease elements, which are principally the test kits, the related revenue is recognized at a point-in-time when control transfers. +(j) +Fair Value Measurements +- Certain assets and liabilities are recorded at fair value in accordance with ASC 820, +Fair Value Measurements and Disclosures +. ASC 820 defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a three-level hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy level assigned to each asset and liability is based on the assessment of the transparency and reliability of the inputs used in the valuation of such items at the measurement date based on the lowest level of input that is significant to the fair value measurement. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). +Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories based on inputs: +Level 1 +Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities +Level 2 +Quoted prices in markets that are not active and financial instruments for which all significant inputs are observable, either directly or indirectly +Level 3 +Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable +(k) +Research and Development Costs +- Research and development costs are charged to expense as incurred. Research and development costs include, among other things, salaries and wages for research scientists, materials and supplies used in the development of new products, costs for development of instrumentation equipment, costs for clinical trials, costs of regulatory compliance activities, and costs for facilities and equipment. +- +55 +- +Table of Contents +(l) +Income Taxes +- The provision for income taxes includes federal, foreign, state and local income taxes currently payable and those deferred because of temporary differences between income for financial reporting and income for tax purposes. We prepare estimates of permanent and temporary differences between income for financial reporting purposes and income for tax purposes. These differences are adjusted to actual upon filing of our tax returns, typically occurring in the third and fourth quarters of the current fiscal year for the preceding fiscal year’s estimates. +The Company has certain deferred income tax assets in select jurisdictions. The recoverability of these deferred income tax assets is assessed periodically, and valuation allowances are recognized if it is determined that it is more likely than not that the benefits will not be realized. When performing the assessment, the Company considers the ability to carryback losses to prior tax periods, future taxable income, the reversal of existing temporary differences, and tax planning strategies. +We account for uncertain tax positions using a benefit recognition model with a two-step approach: (i) a more-likely-than-not recognition criterion; and (ii) a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50 % likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit is recorded. We recognize accrued interest related to unrecognized tax benefits as a portion of our income tax provision in the Consolidated Statements of Operations. +(m) +Stock-Based Compensation +- We recognize compensation expense for all share-based awards made to employees based upon the fair value of the share-based award on the date of the grant. +(n) +Comprehensive Income (Loss) +- Comprehensive income (loss) represents the net change in shareholders’ equity during a period from sources other than transactions with shareholders. As reflected in the Consolidated Statements of Comprehensive Income, our comprehensive income is comprised of net earnings, foreign currency translation, recognition of gains on previous cash flow hedges, unrealized gain (loss) on current cash flow hedge, and the income taxes thereon. +The primary component of accumulated comprehensive income (loss) is cumulative currency translation adjustments, which totaled ($ 11,794 ) and $ 135 at September 30, 2022 and 2021, respectively. +(o) +Shipping and Handling Costs +- Shipping and handling costs invoiced to customers are included in net revenues. Costs to distribute products to customers, including freight costs, warehousing costs, and other shipping and handling activities are included in cost of sales. +(p) +Non-Income Government-Assessed Taxes +- We classify all non-income, government-assessed taxes (sales, use and value-added) collected from customers and remitted by us to appropriate revenue authorities, on a net basis (excluded from net revenues) in the Consolidated Statements of Operations. +(q) +Acquisition +s +- Assets and liabilities associated with business acquisitions are recorded at fair value, using the acquisition method of accounting. The Company allocates the purchase price of acquisitions based upon the fair value of each component, which may be derived from observable or unobservable inputs and assumptions. The Company may utilize third-party valuation specialists to assist us in this allocation. Initial purchase price allocations are preliminary and subject to revision within the measurement period, generally not to exceed one year from the date of acquisition. +(r) +Other expense, net +- Other expense, net, consists principally of transaction currency gains or losses. When a transaction is denominated in a currency other than the subsidiary’s functional currency, the Company recognizes a transaction gain or loss in other expense, net within the Consolidated Statements of Operations when the transaction is settled. +From time to time, the Company enters into short-term (generally 30 days or less) foreign currency forward contracts to manage its exposure to certain foreign currencies. These foreign currency forward contracts are not designated as hedging instruments and, therefore, all changes in fair value and the settlement of the foreign current forward contracts is recorded in other expense, net within the Consolidated Statement of Operations. For the years ended September 30, 2022, 2021 and 2020, we recognized losses of approximately $ 2,100 , $ 100 , and $ 0 , respectively related to foreign currency forward contracts. +- 56 - +Table of Contents +(s) +Recent Accounting Pronouncements +- +Pronouncements Adopted +On October 1, 2021, the Company adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2019-12, +Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes +(“ASU +2019-12 +”), which clarified and simplified accounting for income taxes by eliminating certain exceptions for intraperiod tax allocation principles, the methodology for calculating income tax rates in an interim period, and recognition of deferred taxes for outside basis differences in an investment, among other updates. Adoption of ASU +2019-12 +did not have a material impact on the Consolidated Financial Statements. +Pronouncements Issued but Not Yet Adopted as of September 30, 2022 +In March 2020, the FASB issued ASU 2020-04, +Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting +, to provide temporary optional guidance relating to reference rate reform, particularly as it relates to easing the potential burden resulting from the expected discontinuation of the London Interbank Offered Rate (“LIBOR”). The guidance provides practical expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met, which may be applied through December 31, 2022. The Company continues to evaluate the impacts of this guidance but does not expect its application to have a material impact on the Consolidated Financial Statements. +No other new accounting pronouncements recently adopted or issued had or are expected to have a material impact on the Consolidated Financial Statements. +(t) +Reclassifications +- +Within the notes to the Consolidated Financial Statements, certain reclassifications have been made to the prior year allocation of expenses between segments in order to conform to the current year presentation. Such reclassifications had no impact on any consolidated figures or segment net revenues. +(2) +Revenue Recognition +The following tables present our net revenues disaggregated by major geographic region, major product platform and disease state (Diagnostics segment only): +Net Revenues by Reportable Segment & Geographic Region +Year Ended September 30, +2022 +2021 +2020 +Diagnostics- +Americas +$ +132,175 +$ +101,293 +$ +97,228 +EMEA +22,135 +24,475 +21,826 +ROW +1,593 +1,992 +2,078 +Total Diagnostics +155,903 +127,760 +121,132 +Life Science- +Americas +33,062 +46,063 +37,391 +EMEA +81,305 +93,655 +58,125 +ROW +62,748 +50,418 +37,019 +Total Life Science +177,115 +190,136 +132,535 +Consolidated +$ +333,018 +$ +317,896 +$ +253,667 +- +57 +- +Table of Contents +Net Revenues by Product Platform/Type +Year Ended September 30, +2022 +2021 +2020 +Diagnostics- +Molecular assays +$ +18,177 +$ +19,037 +$ +21,907 +Non-molecular assays +137,726 +108,723 +99,225 +Total Diagnostics +155,903 +127,760 +121,132 +Life Science- +Molecular reagents +91,816 +130,537 +78,431 +Immunological reagents +85,299 +59,599 +54,104 +Total Life Science +177,115 +190,136 +132,535 +Consolidated +$ +333,018 +$ +317,896 +$ +253,667 +Net Revenues by Disease State (Diagnostics only) +Year Ended September 30, +2022 +2021 +2020 +Diagnostics- +Gastrointestinal assays +$ +87,568 +$ +68,890 +$ +55,040 +Respiratory illness assays +26,632 +17,608 +26,694 +Blood chemistry assays +14,189 +15,398 +17,534 +Other +27,514 +25,864 +21,864 +Total Diagnostics +$ +155,903 +$ +127,760 +$ +121,132 +Royalty Income +Royalty income received from a third party related to sales of +H. pylori +products, totaled approximately $ 6,750 , $ 6,330 and $ 3,540 for the years ended September 30, 2022, 2021 and 2020, respectively. Such revenue is included as part of Non-molecular assays and Other within the Net Revenues by Product Platform/Type and Net Revenues by Disease State tables, respectively, above. +Reagent Rental Arrangements +Revenue allocated to the lease elements of Reagent Rental arrangements totaled approximately $ 3,925 , $ 3,710 and $ 4,600 for the years ended September 30, 2022, 2021 and 2020, respectively. Such revenue is included as part of net revenues in our Consolidated Statements of Operations. +(3) +Fair Value Measurements +To limit exposure to volatility in the LIBOR interest rate, the Company has entered into interest rate swap agreements, which effectively convert the variable interest rate on the outstanding revolving credit facility discussed in Note 10 to a fixed rate. The fair values of the interest rate swap agreements were determined by reference to a third-party valuation, which is considered a Level 2 input within the fair value hierarchy of valuation techniques. In conjunction with the paydown of $ 25,000 on the revolving credit facility in March 2022, a $ 25,000 interest rate swap agreement was terminated, resulting in a gain of $ 935 , which is recorded in other expense, net in our Consolidated Statement of Operations for the year ended September 30, 2022. +As indicated in Note 4, we acquired EUPROTEIN Inc. of North Brunswick, New Jersey (“EUPROTEIN”) on April 30, 2022 and BreathTek on July 31, 2021. The fair values of inventories acquired were valued using Level 2 inputs, which included data points that were observable, such as established values of comparable assets and historical sales information (market approach). Identifiable intangible assets, if applicable and specifically the acquired customer relationships, were valued using Level 3 inputs, which are unobservable by nature, and included internal estimates of future cash flows and attrition rates (income approach). Significant increases (decreases) in any of those unobservable inputs, as of the date of the acquisition, in isolation would result in a significantly lower (higher) fair value measurement. +- 5 +8 +- +Table of Contents +In connection with the acquisition of the business of GenePOC, Inc. (“GenePOC”) in fiscal 2019 and subsequent amendments to modify certain terms of the agreement related to contingent consideration achievement levels and milestone dates, the Company was required to make contingent consideration payments of up to $ 64,000 (originally $ 70,000 at the acquisition date), comprised of up to $ 14,000 for achievement of product development milestones (originally $ 20,000 at the acquisition date) and up to $ 50,000 for achievement of certain financial targets. The fair value for the contingent consideration recognized upon the acquisition as part of the purchase price allocation was $ 27,202 . Giving effect to subsequent agreements to modify certain terms of the agreement related to contingent consideration achievement levels and milestone dates, the fair value of the product development milestone payments were estimated by discounting the probability-weighted contingent payments to present value and presented on the Consolidated Balance Sheets based on the Company’s anticipated date of payment at each reporting period. Assumptions used in the calculations included probability of success, duration of the earn-out and discount rate, with such calculations being updated for the effect of the previously noted amendments to the contingent consideration achievement levels and milestone dates. The fair value of the financial performance target payments was determined using a Monte Carlo simulation-based model. Assumptions used in these calculations included expected net revenues, probability of certain developments, expected expenses and discount rate. In August 2021, the Company paid $ 20,000 to settle the contingent consideration obligation, resulting in a $ 909 net gain for the year ended September 30, 2021. +The following table provides information by level for financial assets and liabilities that are measured at fair value on a recurring basis +, the carrying values for which are included within other assets and other non-current liabilities of the September 30, 2022 and 2021 Consolidated Balance Sheets, respectively +: +Fair Value Measurements Using +Inputs Considered as +Carrying +Value +Level 1 +Level 2 +Level 3 +Interest rate swap agreements - +As of September 30 , 2022 +$ +1,421 +$ +— +$ +1,421 +$ +— +As of September 30 , 2021 +$ +( 203 +) +$ +— +$ +( 203 +) +$ +— +Supplemental Cash Flow Information (Non-Cash Acquisition Consideration) +In arriving at the $ 20,000 settlement payment in fiscal 2021, the acquisition consideration obligation related to acquisition of the GenePOC business decreased $ 909 during the year ended September 30, 2021, due in large part to amendment of certain terms of the original contingent consideration achievement levels and milestone dates, as well as the settlement in August 2021. +(4) +Business Combinations +Acquisition of EUPROTEIN +On April 30, 2022, we acquired substantially all of the assets of EUPROTEIN for $ 4,250 in cash, of which $ 3,750 was paid at closing, with the remainder held back for final closing adjustments, which is recorded in other non-current liabilities on the Consolidated Balance Sheets and is payable within 18 months of the acquisition date. EUPROTEIN offers custom development and production of high-quality bioresearch reagents, with a particular focus on human and other mammalian proteins and recombinant monoclonal antibodies. The acquired assets of EUPROTEIN are included within the Life Science segment and are expected to help the Company accelerate its pipeline of new immunological reagents, while expanding recombinant capabilities. The acquired assets, which are comprised of goodwill, property, plant and equipment, prepaid expenses, and inventories, were valued on April 30, 2022, on a preliminary basis at $ 3,947 , $ 279 , $ 14 and $ 10 , respectively. +The goodwill for EUPROTEIN is attributable to combining EUPROTEIN and Meridian’s products and capabilities to give the Company’s customers access to new immunological reagents. The goodwill is not expected to be deductible for income tax purposes. The preliminary purchase price allocation may change in the future as the fair valuing of assets is completed. +- +59 +- +Table of Contents +Acquisition of BreathTek Business +On July 31, 2021, we acquired BreathTek, a urea breath test for the detection of +H. pylori +, from Otsuka America Pharmaceutical, Inc. Cash consideration totaled $ 19,585 , subject to a $ 1,000 holdback, which is recorded in other accrued expenses and other non-current liabilities on the Consolidated Balance Sheets as of September 30, 2022 and 2021, respectively, to secure the selling party’s performance of certain post-closing obligations and is payable 15 months following the BreathTek acquisition date. As part of the acquisition, we acquired BreathTek inventories and assumed the customer relationships to supply the BreathTek product in North America. Giving effect to purchase adjustments made during the permitted measurement period to increase the value of acquired inventories by approximately $ 100 , the final acquired inventories and customer relationships were valued on July 31, 2021 at $ 9,955 and $ 9,630 , respectively, with the useful life of the customer relationships estimated at five years . +The Company’s consolidated results include approximately the following from BreathTek products: +Year Ended September 30, +2022 +2021 +Net revenues +$ +23,100 +$ +3,840 +Net +earnings +7,500 +1,000 +These results, which are reported as part of the Diagnostics segment, include amortization expense related to the customer relationships recorded in the purchase price allocation totaling $ 1,919 and $ 324 for the years ended September 30, 2022 and 2021, respectively. +Unaudited Pro Forma Information +The following table provides the unaudited consolidated pro forma results for the periods presented as if the BreathTek business had been acquired as of the beginning of fiscal 2021: +Year Ended September 30, +2022 +2021 +Net revenues +$ +333,018 +$ +337,118 +Net earnings +42,459 +77,066 +Based on the nature of the EUPROTEIN business, EUPROTEIN is not expected to contribute materially to net revenues and net earnings and therefore, no amounts are included in the table above. +(5) +Lead Testing Matters +On September 1, 2021, the Company’s wholly owned subsidiary Magellan announced the expansion of the Class I voluntary recall of its LeadCare test kits for the detection of lead in blood, which it had initiated in May 2021 after identifying an issue in certain manufactured lots of its LeadCare test kits. As a result of the identified issue, impacted test kit lots could potentially underestimate blood lead levels when processing patient blood samples. Although it was initially believed that the root cause of the issue related to the plastic containers used for the treatment reagent, additional studies have indicated that the root cause related to the third-party-sourced cardboard trays that held the treatment reagent containers. Upon correction of the identified supplier issue, shipment of product resumed during the second quarter of fiscal 2022. The Company continues to work closely with the FDA in its execution of the recall activities, which +has included +Magellan notifying customers and distributors affected by the recall and providing instructions for the return of impacted test kits. Of the $ 5,100 estimated and accrued as of September 30, 2021 to cover the estimated costs of the recall, it was estimated at September 30, 2022 that the remaining costs of the recall exceeded the amount accrued, and as a result, an adjustment was made to the product recall reserve. The effect of this adjustment is reflected in product recall costs (adjustment) within the Consolidated Statement of Operations for the year ended September 30, 2022, and results in approximately $ 430 of remaining accrued product recall costs reflected in the Consolidated Balance Sheet as of September 30, 2022. Anticipated recall-related costs primarily include +temporary labor costs, +product replacement and/or refund costs, mailing/shipping costs, attorneys’ fees and other miscellaneous costs. Information utilized in the accrual estimation process includes observable inputs such as customer on-hand inventory data, product sales data, average sales price, and product inventory turns, among other things. +- +60 +- +Table of Contents +On April 17, 2018 , the Company’s wholly owned subsidiary Magellan received a subpoena from the U.S. Department of Justice (“DOJ”) regarding its LeadCare product line. The subpoena outlined documents to be produced, and the Company is cooperating with the DOJ in this matter. The Company maintains rigorous policies and procedures to promote compliance with applicable regulatory agencies and requirements and is working with the DOJ to promptly respond to the subpoena, including responding to additional information requests that have followed receipt of the subpoena in April 2018. The Company has executed tolling agreements to extend the statute of limitations. In March and April 2021, DOJ issued two subpoenas, both to former employees of Magellan, calling for witnesses to testify before a federal grand jury related to this matter. In September and October 2021, DOJ issued additional subpoenas to individuals seeking testimony and documents in connection with its ongoing investigation. It is the Company’s understanding that multiple witnesses have testified before the federal grand jury and the DOJ’s investigation is ongoing. Discussions continue with the DOJ to explore resolution of the matter. As of September 30, 2022, +in accordance with applicable accounting guidance, +the Company believes a loss is probable in the DOJ LeadCare legal matter and has accrued $ 10,000 as +an estimate of the cost to resolve the DOJ LeadCare legal matter, which is reflected in litigation and select legal costs within the Consolidated Statement of Operations for the year ended September 30, 2022. The Company estimated this cost based on discussions with the DOJ. The Company cannot predict when the investigation will be resolved or the outcome of the investigation, and the ultimate resolution of the DOJ LeadCare legal matter may exceed the amount accrued at September 30, 2022 and could be material to the Company. Expense for attorneys’ fees related to this matter +totaling $ 3,510 , $ 2,803 and $ 2,035 is included within the Consolidated Statements of Operations for the years ended September 30, 2022, 2021 and 2020, respectively. +Magellan submitted 510(k) applications in December 2018, seeking to reinstate venous blood sample-types for its LeadCare II, LeadCare Plus and LeadCare Ultra testing systems. In the second fiscal quarter of 2019, the FDA informed Magellan that each of these 510(k) applications had been put on Additional Information hold. On July 15, 2019, we provided responses to the FDA’s requests for Additional Information. These 510(k) applications have since expired and are no longer under FDA review. Further, while Magellan’s LeadCare testing systems remain cleared for marketing by the FDA and permitted for use with capillary blood samples, the FDA advised that it has commissioned a third-party study of the Company’s LeadCare testing systems using both venous and capillary blood samples. According to the FDA, the results of the field study will be used in conjunction with other information to determine whether further action by the FDA or the Centers for Disease Control and Prevention (“CDC”) is necessary to protect the public health. The Company intends to fully cooperate with the FDA or CDC on any follow-up based on the third-party study. +During October 2019, the FDA performed a follow-up inspection of Magellan’s manufacturing facility. The FDA issued five Form FDA 483 observations. On March 18, 2020, we participated in a regulatory meeting with the FDA at the FDA’s request to further discuss the Form FDA 483 observations and our remediation efforts. Since the inspection, we have submitted a number of written responses to the FDA regarding the five Form FDA 483 observations issued in the October 2019 inspection, and have worked diligently to execute a remediation plan. During October 2020, the FDA issued Establishment Inspection Reports which closed out the inspections from June 2017 and October 2019 under 21 C.F.R.20.64(d)(3). +During June 2021, the FDA performed an inspection of Magellan’s manufacturing facility. As a result of this inspection, the FDA issued one Form 483 observation. On August 3, 2021, FDA sent Magellan a close-out letter for the Warning Letter that FDA issued to Magellan on October 23, 2017. FDA’s close-out letter notified Magellan that FDA has completed an evaluation of Magellan’s corrective actions in response to FDA’s Warning Letter, and based on FDA’s evaluation, Magellan has addressed the issues identified in the Warning Letter. FDA’s close-out letter also stated that future FDA inspections of Magellan and regulatory activities will further assess the adequacy and sustainability of Magellan’s corrections. +- +61 +- +Table of Contents +(6) +Cash and Cash Equivalents +Cash and cash equivalents are comprised of the following: +As of September 30, +2022 +2021 +Institutional money market funds +$ +1,027 +$ +1,020 +Cash on hand, unrestricted +80,426 +48,751 +Total +$ +81,453 +$ +49,771 +Cash equivalents and institutional money market funds are classified within Level 1 of the fair value hierarchy. Financial instruments classified as Level 1 are based on quoted market prices in active markets. The Company does not adjust the quoted market price for such financial instruments. +(7) +Inventories, Net +Inventories, net are comprised of the following: +As of September 30, +2022 +2021 +Raw materials +$ +15,726 +$ +14,843 +Work-in-process +21,570 +25,072 +Finished goods - instruments +1,796 +2,260 +Finished goods - kits and reagents +28,722 +34,667 +Total +$ +67,814 +$ +76,842 +(8) +Goodwill and Other Intangible Assets, Net +During fiscal 2022, goodwill increased $ 1,634 , comprised of the following: (i) a $ 492 decrease in Diagnostics segment goodwill; and (ii) a $ 2,126 increase in Life Science segment goodwill. This overall increase in goodwill reflects $ 3,947 of goodwill acquired in the EUPROTEIN acquisition (see Note 4), partially offset by the effects of foreign currency translation. +During fiscal 2021, goodwill increased $ 482 , reflecting: (i) a $ 56 increase from the currency translation adjustment on goodwill in the Diagnostics segment; (ii) a $ 433 increase from the currency translation adjustment on goodwill in the Life Science segment; and (iii) a $ 7 decrease related to Exalenz, reflecting additional measurement period adjustments. +A summary of Meridian’s intangible assets subject to amortization is as follows: +2022 +2021 +As of September 30, +Gross +Carrying +Value +Accum. +Amort. +Gross +Carrying +Value +Accum. +Amort. +Manufacturing technologies, core products and cell lines +$ +56,289 +$ +20,321 +$ +64,867 +$ +25,084 +Tradenames, licenses and patents +18,257 +10,491 +18,489 +9,492 +Customer lists, customer relationships and supply agreements +52,703 +22,363 +54,941 +19,649 +Non-compete agreements +110 +53 +110 +31 +$ +127,359 +$ +53,228 +$ +138,407 +$ +54,256 +The aggregate amortization expense for these intangible assets for the years ended September 30, 2022, 2021 and 2020 was $ 9,912 , $ 8,776 and $ 7,744 , respectively. The estimated aggregate amortization expense for these intangible assets for each of the five succeeding fiscal years is as follows: fiscal 2023 - $ 9,905 , fiscal 2024 - $ 9,900 , fiscal 2025 - $ 9,890 , fiscal 2026 - $ 8,900 and fiscal 2027 - $ 6,645 . +- 62 - +Table of Contents +(9) +Leasing Arrangements +The Company is party to several operating leases, the majority of which are related to office, warehouse and manufacturing space. The related operating lease assets and obligations are reflected within right-of-use assets, net, current operating lease obligations and long-term operating lease obligations on the Consolidated Balance Sheets. Lease expense for these leases is recognized on a straight-line basis over the lease term, with variable lease payments recognized in the period those payments are incurred. +The lease costs for these operating leases reflected in our Consolidated Statements of Operations, as well as the right-of-use assets, net obtained during these periods in exchange for operating lease liabilities, are as follows: +Year Ended September 30, +2022 +2021 +Lease costs within cost of sales +$ +905 +$ +795 +Lease costs within operating expenses +1,406 +1,542 +Right-of-use assets, net obtained in exchange for operating lease liabilities +3,068 +1,073 +In addition, the Company periodically enters into other short-term operating leases, generally with an initial term of twelve months or less. These leases are not recorded on the Consolidated Balance Sheets and the related lease expense is immaterial for fiscal 2022, 2021 and 2020. +The Company often has options to renew lease terms, with the exercise of lease renewal options generally at the Company’s sole discretion. In addition, certain lease arrangements may be terminated prior to their original expiration date at our discretion. We evaluate renewal and termination options at the lease commencement date to determine if we are reasonably certain to exercise the option on the basis of economic factors. The discount rate implicit within our leases is generally not determinable and, therefore, the Company uses its incremental borrowing rate as the basis for its discount rate. The weighted average remaining lease term for our operating leases and the weighted average discount rate used to measure our operating leases were as follows: +As of September 30, +2022 +2021 +Weighted average remaining lease term +3.9 yrs. +3.6 yrs. +Average discount rate +3.5 +% +3.2 +% +Maturities of lease liabilities by fiscal year for the Company’s operating lease liabilities were as follows as of September 30, 2022: +2023 +$ +1,952 +2024 +1,614 +2025 +1,343 +2026 +780 +2027 +536 +Thereafter +135 +Total lease payments +6,360 +Less amount of lease payment representing interest +( 403 +) +Total present value of lease payments +$ +5,957 +- +63 +- +Table of Contents +Supplemental Cash Flow Information (Cash Paid for Amounts Included in Measurement of Lease Liabilities) +Year Ended September 30, +2022 +2021 +2020 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases +$ +2,338 +$ +2,228 +$ +1,693 +(10) +Bank Credit Arrangements +The Company maintains a revolving credit facility with a commercial bank in an aggregate principal amount not to exceed $ 200,000 , which expires in October 2026 . Outstanding principal amounts bear interest at a fluctuating rate tied to, at the Company’s option, either the federal funds rate or LIBOR, resulting in an effective interest rate of 2.69 % and 2.51 % on the revolving credit facility during fiscal 2022 and 2021, respectively. In light of the interest being determined on a variable rate basis, the fair value of the borrowings under the credit facility at both September 30, 2022 and 2021 approximates the current carrying value reflected in the Consolidated Balance Sheets of $ 25,000 and $ 60,000 , respectively, which is consistent with a level 2 fair value measurement. +The revolving credit facility is collateralized by the business assets of the Company’s U.S. subsidiaries and requires compliance with financial covenants that limit the amount of debt obligations and require a minimum level of coverage of fixed charges, as defined in the revolving credit facility agreement. As of September 30, 2022, the Company was in compliance with all covenants. +Supplemental Cash Flow Information (Interest Paid) +Cash paid for interest totaled $ 934 , $ 1,348 and $ 2,690 in fiscal 2022, 2021 and 2020, respectively. +(11) +Income Taxes +(a) +Earnings before income taxes, and the related income tax provision were as follows: +Year Ended September 30, +2022 +2021 +2020 +Domestic +$ +( 14,012 +) +$ +11,354 +$ +9,068 +Foreign +68,329 +79,097 +50,225 +Total earnings before income taxes +$ +54,317 +90,451 +59,293 +Provision (benefit) for income taxes - +Federal - +Current +$ +( 460 +) +$ +4,431 +$ +1,173 +Deferred +( 1,125 +) +( 2,595 +) +744 +State and local +451 +1,163 +1,170 +Foreign - +Current +13,316 +16,305 +10,194 +Deferred +( 324 +) +( 260 +) +( 174 +) +Total income tax provision +$ +11,858 +$ +19,044 +$ +13,107 +- +64 +- +Table of Contents +(b) +The following is a reconciliation between the statutory U.S. income tax rate and the effective rate derived by dividing the income tax provision by earnings before income taxes: +Year Ended September 30, +2022 +2021 +2020 +Computed income taxes at statutory rate +$ +11,407 +21.0 +% +$ +18,995 +21.0 +% +$ +12,452 +21.0 +% +Increase (decrease) in taxes resulting from - +State and local income taxes +362 +0.7 +1,204 +1.3 +773 +1.3 +Foreign-Derived Intangible Income tax +— +— +( 563 +) +( 0.6 +) +( 136 +) +( 0.2 +) +Global Intangible Low Taxed Income (“GILTI”) tax +6,924 +12.7 +8,061 +8.9 +4,970 +8.4 +Foreign tax credit +( 6,572 +) +( 12.1 +) +( 7,802 +) +( 8.6 +) +( 4,767 +) +( 8.0 +) +Foreign tax rate differences +( 1,679 +) +( 3.1 +) +( 869 +) +( 1.0 +) +( 534 +) +( 0.9 +) +DOJ LeadCare legal matter accrual +2,100 +3.9 +— +— +— +— +Uncertain tax position activity +166 +0.3 +205 +0.2 +62 +0.1 +Valuation allowance +( 197 +) +( 0.4 +) +729 +0.8 +229 +0.3 +Stock-based compensation +825 +1.5 +( 498 +) +( 0.5 +) +41 +0.1 +Transaction costs +— +— +— +— +548 +0.9 +Unrepatriated earnings +( 1,148 +) +( 2.1 +) +680 +0.8 +185 +0.3 +Other, net +( 330 +) +( 0.6 +) +( 1,098 +) +( 1.2 +) +( 716 +) +( 1.2 +) +$ +11,858 +21.8 +% +$ +19,044 +21.1 +% +$ +13,107 +22.1 +% +The Company’s GILTI and foreign tax credit details were as follows: +Year Ended September 30, +2022 +2021 +2020 +U.S. GILTI inclusion +$ +32,971 +$ +38,384 +$ +23,666 +Resulting permanent tax expense +6,924 +8,061 +4,970 +Offsetting foreign tax credit +( 6,572 +) +( 7,802 +) +( 4,767 +) +(c) +The components of net deferred taxes were as follows: +As of September 30, +2022 +2021 +Deferred tax assets - +Valuation reserves and non-deductible expenses +$ +4,274 +$ +4,939 +Stock compensation expense not deductible +2,609 +2,276 +Net operating loss and tax credit carryforwards +12,108 +12,711 +Intangible asset basis differences and amortization +1,254 +505 +Unrepatriated earnings +1,205 +— +Other +1,357 +1,512 +Subtotal +22,807 +21,943 +Less valuation allowance +( 1,427 +) +( 1,624 +) +Deferred tax assets +21,380 +20,319 +Deferred tax liabilities - +Property, plant and equipment basis differences and depreciation +( 5,540 +) +( 4,778 +) +Intangible asset basis differences and amortization +( 6,218 +) +( 7,000 +) +Unrepatriated earnings +( 922 +) +( 865 +) +Deferred tax liabilities +( 12,680 +) +( 12,643 +) +Net deferred tax assets +$ +8,700 +$ +7,676 +- +65 +- +Table of Contents +For income tax purposes, we have recorded deferred tax assets related to operating loss and tax credit carryforwards of +$ 12,108 +in foreign jurisdictions as of September 30, 2022, reduced by valuation reserves totaling +$ 1,125 . +At September 30, 2021, such deferred tax assets totaled +$ 179 and $ 12,532 +in U.S. and foreign jurisdictions, respectively, reduced by valuation reserves totaling +$ 1,322 . +The operating loss carryforwards in foreign jurisdictions, the majority of which relate to Israel, have no expiration date. The aggregate amount of foreign operating loss carryforwards totaled approximately +$ 87,000 +at September 30, 2022 +. +The Company has recognized a net deferred tax asset +of $ +283 +and a +net +deferred tax liability of $ +865 +at September 30, 2022 and 2021, respectively, related to unrepatriated foreign earnings. +The realization of deferred tax assets is dependent upon the generation of future taxable income in the applicable jurisdictions. We have considered the levels of currently anticipated pre-tax income in U.S. and foreign jurisdictions in assessing the required level of the deferred tax asset valuation allowance including the characterization of the income as ordinary or capital. Taking into consideration historical and current operating results, and other factors, we believe that it is more likely than not that the net deferred tax asset of $ 21,380 will be realized. The amount of the net deferred tax asset considered realizable, however, could be reduced in future years if estimates of future taxable income are reduced. +We utilize a comprehensive model for the recognition, measurement, presentation and disclosure of uncertain tax positions, assuming full knowledge of all relevant facts by the applicable tax authorities. The total amount of unrecognized tax benefits at September 30, 2022 and 2021 related to such positions was $ 774 and $ 700 , respectively, of which $ 700 at September 30, 2022 would favorably impact the effective tax rate if recognized. We generally recognize interest and penalties related to uncertain tax positions as a component of our income tax provision. During fiscal 2022 and 2021, such penalties and interest totaled approximately $ 24 and $ 31 , respectively. We had approximately $ 194 accrued for the payment of interest and penalties at September 30, 2022, compared to $ 170 accrued at September 30, 2021. The amount of our liability for uncertain tax positions expected to be paid or settled in the next 12 months is uncertain. +A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: +Year Ended September 30, +2022 +2021 +2020 +Unrecognized income tax benefits at beginning of year +$ +700 +$ +568 +$ +509 +Additions for tax positions of prior years +— +34 +— +Reductions for tax positions of prior years +— +— +— +Additions for tax positions of current year +138 +138 +104 +Tax examination and other settlements +( 64 +) +( 40 +) +( 45 +) +Unrecognized income tax benefits at end of year +$ +774 +$ +700 +$ +568 +We are subject to examination by the tax authorities in the U.S. (both federal and state) and the countries of Australia, Belgium, Canada, China, England, France, Germany, Holland, Israel and Italy. In the U.S., tax years subsequent to fiscal 2018 remain open . In countries outside the U.S., open tax years generally range from fiscal 2017 and forward . However, in Australia and Belgium, the utilization of local net operating loss carryforwards extends the statute of limitations for examination well into the foreseeable future. To the extent that adjustments result from the completion of these examinations or the lapsing of statutes of limitation, they will affect tax liabilities in the period known. We believe that the results of any tax authority examinations would not have a significant adverse impact on our consolidated financial condition or results of operations. +Supplemental Consolidated Cash Flow Information (Income Taxes Paid) +Cash paid for income taxes totaled $ 26,824 , $ 27,466 and $ 9,816 in fiscal 2022, 2021 and 2020, respectively. +- +66 +- +Table of Contents +(12) +Employee Benefits +(a) +Savings and Investment Plan +- We have a profit sharing and retirement savings plan covering substantially all full-time U.S. employees. Profit sharing contributions to the plan, which are discretionary, are approved by the board of directors. The plan permits participants to contribute to the plan through salary reduction. Under terms of the plan, we match 100 % of an employee’s contributions, up to a maximum match of 4 % of eligible compensation. Our discretionary and matching contributions to the plan, which are recorded primarily within operating expenses, amounted to approximately $ 2,727 , $ 2,869 and $ 2,434 , for the years ended September 30, 2022, 2021 and 2020, respectively. +(b) +Stock-Based Compensation Plans +- During fiscal 2022, the Company had two active stock-based compensation plans, the 2012 Stock Incentive Plan, which became effective January 25, 2012 (the “2012 Plan”) and the 2021 Omnibus Award Plan, which became effective January 27, 2021 (the “2021 Plan”). +The 2021 Plan is authorized to grant new shares for options, restricted shares or restricted share units for up to 2,839 shares, including 1,839 non-granted shares from the 2012 Plan permitted to be carried forward and added to the 2021 Plan authorized limit. +Considering grants, cancellation and forfeitures that have occurred during the year, as +of September 30, 2022, +the +remaining authorized limit +under the 2021 Plan totals approximately +2,200 shares. Options may be granted at exercise prices not less than 100 % of the closing market value of the underlying common shares on the date of grant and have maximum terms up to ten years . Vesting schedules for options, restricted shares and restricted share units are established at the time of grant and may be set based on future service periods, achievement of performance targets, or a combination thereof. All options contain provisions restricting their transferability and limiting their exercise in the event of termination of employment, or the disability or death of the optionee. We recognize compensation expense for all share-based payments made to employees, based upon the fair value of the share-based payment on the date of the grant. +During fiscal years 2020 through 2022, we granted, in the aggregate for the three-year period, approximately 875 restricted share units (with weighted-average grant date fair values of $ 10.13 per share in fiscal 2020, $ 18.81 per share in fiscal 2021 and $ 20.50 per share in fiscal 2022) to certain employees, including CEO Jack Kenny, as separately detailed below. The units granted in fiscal 2022 were generally time-vested restricted share units vesting in total on the fourth anniversary of the grant date, while units granted in fiscal 2021 and 2020 were generally time-vested restricted share units vesting in total on the third anniversary of the grant date. +Additionally, during fiscal 2022, we granted approximately 105 restricted share units (with a weighted-average grant date fair value of $ 19.54 per share) to certain employees, including +Mr. +Kenny to incentivize the achievement of certain Company and segment net revenues and operating targets in fiscal 2024. These awards can only be earned if specified net revenues and operating income thresholds are achieved during fiscal 2024, with increased amounts available to be earned as established increased levels are achieved, which range from 50 % to 200 % of the “targeted” payout. Based upon information available as September 30, 2022, it is estimated that these performance-based restricted stock units will be paid out at the target level, and the associated stock compensation expense is being recorded ratably through September 30, 2024. Such expense totaled approximately $ 510 during fiscal 2022. +During fiscal 2020, in connection with Mr. Kenny’s Amended and Restated Employment Agreement, effective October 1, 2019, we granted to Mr. Kenny: (i) options to purchase approximately 198 shares of common stock of the Company (with a grant date fair value of $ 3.38 per share) vesting on a pro rata basis over the three years ending October 1, 2022 ; and (ii) approximately 100 restricted share units (with a grant date fair value of $ 10.10 per share) vesting 100 % on the October 1, 2022, which are included within the restricted share units noted above. +Giving effect to these grants, cancellations and certain other activities for restricted shares and restricted share units throughout the years, including conversions to common shares, forfeitures, and new hire and employee promotion grants, approximately 790 restricted share units remain outstanding as of September 30, 2022, with a weighted-average grant date fair value of $ 15.93 per share, a weighted-average remaining vesting period of 1.08 years and an aggregate intrinsic value of $ 24,898 . The weighted-average grant date fair value of the approximate 306 restricted share units that vested during fiscal 2022 was $ 17.34 per share. +- +67 +- +Table of Contents +The amount of stock-based compensation expense was $ 6,900 , $ 4,156 and $ 3,802 for the years ended September 30, 2022, 2021 and 2020, respectively. The fiscal 2022 expense is comprised of $ 1,414 related to stock options and $ 5,486 related to restricted share units; the fiscal 2021 expense is comprised of $ 1,080 related to stock options and $ 3,076 related to restricted share units ; and the fiscal 2020 expense is comprised of $ 1,006 related to stock options and $ 2,796 related to restricted share units. The total income tax benefit recognized in the Consolidated Statements of Operations for these stock-based compensation arrangements was $ 1,638 , $ 1,516 and $ 898 , for the years ended September 30, 2022, 2021 and 2020, respectively. As of September 30, 2022, we expect future stock compensation expense for unvested options and unvested restricted share units to total $ 905 and $ 5,821 , respectively, which will be recognized during fiscal years 2023 through 2026 . +We recognize stock-based compensation expense only for the portion of shares that we expect to vest. As such, we apply estimated forfeiture rates to our stock-based compensation expense calculations. These rates have been derived using historical forfeiture data, stratified by several employee groups, and range from 0 % to 16 % in each of the years ended September 30, 2022, 2021 and 2020. During the years ended September 30, 2022, 2021 and 2020, we recorded $ 192 , $ 183 and $ 148 , respectively, in stock-based compensation expense to adjust estimated forfeiture rates to actual. +We have elected to use the Black-Scholes option pricing model to determine grant-date fair value for stock options, with the following assumptions: (i) expected share price volatility based on the average of Meridian’s historical volatility over the options’ expected lives and implied volatility based on the value of tradable call options; (ii) expected life of options based on contractual lives, employees’ historical exercise behavior and employees’ historical post-vesting employment termination behavior; (iii) risk-free interest rates based on treasury rates that correspond to the expected lives of the options; and (iv) dividend yield based on the expected yield on underlying Meridian common stock. A summary of these key assumptions are as follows: +Year ended September 30, +2022 +2021 +2020 +Share price volatility +51 %- 59 % +53 %- 59 +% +34 +% +Life of option +4.00 - 7.06 yrs. +4.00 - 7.47 yrs. +6.51 yrs. +Risk-free interest rates +0.95 %- 1.73 % +0.26 %- 0.79 +% +1.60 +% +Dividend yield +0 % +0 +% +0 +% +A summary of the status of our stock option plans as of September 30, 2022, and changes during the year ended September 30, 2022, is presented in the table and narrative below: +Options +Wtd Avg +Exercise +Price +Wtd Avg +Remaining +Life (Yrs) +Aggregate +Intrinsic +Value +Outstanding beginning of period +1,001 +$ +15.31 +Grants +163 +19.52 +Exercises +( 186 +) +13.27 +Forfeitures +— +— +Cancellations +( 9 +) +20.26 +Outstanding end of period +969 +$ +16.55 +6.19 +$ +14,515 +Exercisable end of period +612 +$ +16.62 +4.97 +$ +9,124 +- +6 +8 +- +Table of Contents +A summary of the status of our nonvested options as of September 30, 2022, and changes during the year ended September 30, 2022, is presented below: +Options +Weighted- +Average +Grant Date +Fair Value +Nonvested beginning of period +403 +$ +5.70 +Granted +163 +9.26 +Vested +( 209 +) +5.73 +Forfeitures +— +— +Nonvested end of period +357 +$ +7.30 +For the years ended September 30, 2022, 2021 and 2020: (i) the weighted average grant-date fair value of options granted was $ 9.26 , $ 9.18 and $ 3.54 , respectively; (ii) the total intrinsic value of options exercised was $ 3,032 , $ 2,890 and $ 1,585 , respectively; and (iii) the total grant-date fair value of options that vested was $ 1,187 , $ 621 and $ 528 , respectively. +Cash received from options exercised was $ 2,450 , $ 3,052 and $ 3,559 for the years ended September 30, 2022, 2021 and 2020, respectively. +(13) +Contingent Obligations and Non-Current Liabilities +In connection with the acquisition of Exalenz Bioscience Ltd. (“Exalenz”) in fiscal 2020, the Company assumed several Israeli government grant obligations. The repayment of the grants, along with interest incurred at varying stated fixed rates based on LIBOR at the time each grant was received, is not dictated by an established repayment schedule. Rather, the grants and related interest are required to be repaid using 3 % of the net revenues generated from the sales of BreathID products, with the timing of repayment contingent upon the level and timing of such revenues. In addition, the grants have no collateral or financial covenant provisions generally associated with traditional borrowing instruments. These obligation amounts total $ 5,287 and $ 5,814 as of September 30, 2022 and 2021, with the grant obligations remaining at September 30, 2022 bearing interest at rates ranging from 0.58 % to 2.02 %. +The grant obligations are reflected in the Consolidated Balance Sheets as follows: +Year Ended September 30, +2022 +2021 +Current liabilities +$ +667 +$ +638 +Non-current liabilities +4,620 +5,176 +Additionally, the Company has provided certain post-employment benefits to its former Chief Executive Officer, and these obligations total $ 1,284 and $ 1,676 at September 30, 2022 and 2021, respectively. In addition, the Company is required by the governments of certain foreign countries in which we operate to maintain a level of accruals for potential future severance indemnity. These accruals total $ 566 and $ 754 at September 30, 2022 and 2021, respectively. +(14) +National Institutes of Health Contracts +In December 2020, the Company entered into a sub-award grant contract with the University of Massachusetts Medical School as part of the National Institutes of Health Rapid Acceleration of Diagnostics (“RADx”) initiative to support the Company’s research and development of its diagnostic test for the SARS-CoV-2 antigen. The Company has received $ 1,000 under the grant contract for reimbursement of eligible research and development expenditures. These amounts ar +e +included within other expense +, net +in the Consolidated Statement of Operations for the year ended September 30, 2021. +- +69 +- +Table of Contents +On January 25, 2022, the Company entered into a contract to amend the Company’s second grant contract under the RADx initiative, which was originally effective February 1, 2021. The purpose of the grant is to support the Company’s manufacturing production scale-up and expansion to meet the demand for COVID-19 testing, as well as the Company’s Revogene respiratory panel. The amended contract is a 24 -month service contract through January 2023, with payment of up to $ 8,000 being made based on the Company achieving key milestones related to increasing its capacity to produce COVID-19 tests and the Revogene respiratory panel. As of September 30, 2022, $ 2,750 has been received related to this contract and is reflected as a reduction in the cost of building and improvements on the Consolidated Balance Sheet, in accordance with applicable accounting guidance. +(15) +Reportable Segments and Major Concentration Data +The Company’s reportable segments maintain separate financial information for which results of operations are evaluated on a regular basis by the Company’s chief operating decision maker in deciding how to allocate resources and in assessing performance. +The Company records the direct costs of business operations to the reportable segments, including allocations for certain corporate-wide costs such as treasury management, human resources and technology, among others. Corporate provides certain executive management and administrative services to each reportable segment. These services primarily include executive oversight by non-segment-specific executives, including the Board of Directors, along with certain other corporate-wide support functions such as insurance, legal and business development. The Company generally does not allocate these types of corporate expenses to the reportable segments. +Reportable segment and corporate information is as follows: +Diagnostics +Life Science +Corporate +(1) +Eliminations +(2) +Total +Fiscal 2022 +Net revenues - +Third-party +$ +155,903 +$ +177,115 +$ +— +$ +— +$ +333,018 +Inter-segment +255 +138 +— +( 393 +) +— +Operating income (loss) +2,982 +86,040 +( 34,707 +) +76 +54,391 +Depreciation and amortization +14,708 +1,803 +— +— +16,511 +Capital expenditures +6,882 +1,733 +— +— +8,615 +Goodwill +94,412 +21,890 +— +— +116,302 +Other intangible assets, net +74,129 +2 +— +— +74,131 +Total assets +357,630 +105,511 +— +( 44 +) +463,097 +Fiscal 2021 +Net revenues - +Third-party +$ +127,760 +$ +190,136 +$ +— +$ +— +$ +317,896 +Inter-segment +351 +207 +— +( 558 +) +— +Operating income (loss) +( 7,280 +) +115,014 +( 14,788 +) +88 +93,034 +Depreciation and amortization +13,432 +1,854 +— +— +15,286 +Capital expenditures +15,827 +2,485 +— +— +18,312 +Goodwill +94,904 +19,764 +— +— +114,668 +Other intangible assets, net +84,149 +2 +— +— +84,151 +Total assets +339,208 +110,536 +— +( 22 +) +449,722 +Fiscal 2020 +Net revenues - +Third-party +$ +121,132 +$ +132,535 +$ +— +$ +— +$ +253,667 +Inter-segment +326 +261 +— +( 587 +) +— +Operating income (loss) +5,276 +68,893 +( 12,895 +) +50 +61,324 +Depreciation and amortization +11,451 +2,116 +— +— +13,567 +Capital expenditures +1,850 +1,449 +— +— +3,299 +Goodwill +94,855 +19,331 +— +— +114,186 +Other intangible assets, net +83,179 +18 +— +— +83,197 +Total assets +306,812 +98,483 +— +( 34 +) +405,261 +(1) +Includes acquisition and transaction related costs, litigation and select legal costs and restructuring costs totaling $ 20,298 , $ 2,803 and $ 2,080 for the years ended September 30, 2022, 2021 and 2020, respectively +.(2) +Eliminations consist of inter-segment transactions. +- 70 - +Table of Contents +A reconciliation of reportable segment operating income to consolidated earnings before income taxes is as follows: +Year Ended September 30, +2022 +2021 +2020 +Operating income (loss): +Diagnostics segment +$ +2,982 +$ +( 7,280 +) +$ +5,276 +Life Science segment +86,040 +115,014 +68,893 +Eliminations +76 +88 +50 +Total reportable segment operating income +89,098 +107,822 +74,219 +Corporate operating expenses +( 34,707 +) +( 14,788 +) +( 12,895 +) +Interest income +17 +— +142 +Interest expense +( 1,189 +) +( 1,878 +) +( 2,632 +) +RADx initiative grant income +— +1,000 +— +Other, net +1,098 +( 1,705 +) +459 +Consolidated earnings before income taxes +$ +54,317 +$ +90,451 +$ +59,293 +Transactions between reportable segments are accounted for at established intercompany prices for internal and management purposes with all intercompany amounts eliminated in consolidation. +Net revenues generated by the Company’s three major Diagnostics segment product families – gastrointestinal, respiratory illnesses and blood chemistry – accounted for 39 %, 32 % and 39 % of consolidated net revenues during the years ended September 30, 2022, 2021 and 2020, respectively. +While no individual Diagnostics or Life Science segment customers accounted for greater than 10 % of consolidated net revenues during the years ended September 30, 2022, 2021 and 2020, individual Diagnostics or Life Science segment customers, including their affiliates, comprising 10 % or more of reportable segment net revenues were as follows: +Year Ended September 30, +2022 +2021 +2020 +Diagnostics +Customer A +8 +% +10 +% +12 +% +Customer B +10 +% +11 +% +13 +% +Customer C +11 +% +12 +% +7 +% +Life Science +Customer D +3 +% +3 +% +13 +% +Customer E +10 +% +13 +% +11 +% +Customer F +18 +% +4 +% +— +% +- +71 +- +Table of Contents +In addition, for the years ended September 30, 2022, 2021 and 2020, the Life Science segment’s ten largest customers, including their affiliates, accounted for approximately 56 %, 44 % and 48 %, respectively, of Life Science segment net revenues, and 30 %, 27 % and 25 %, respectively, of consolidated net revenues. +One Diagnostics segment customer (Customer B above) and one Life Science segment customer (not listed above) accounted for approximately 12 % and 11 %, respectively, of consolidated accounts receivable as of September 30, 2022. As of September 30, 2021, +o +ne Diagnostics segment customer (Customer B above) and one Life Science segment customer (Customer E above) accounted for approximately 12 % and 10 %, respectively, of consolidated accounts receivable. +Net revenues generated by the Company outside of the U.S. and its territories totaled $ 170,467 , $ 173,475 and $ 121,596 for the years ended September 30, 2022, 2021 and 2020, respectively, with net revenues by country for the Diagnostics and Life Science segments as follows (net revenues are attributed to the geographic area based on the location to which the product is delivered): +Year Ended September 30, +2022 +2021 +2020 +U.S. and territories +$ +130,101 +$ +99,636 +$ +95,382 +Italy +9,741 +12,240 +9,797 +United Kingdom +3,972 +2,197 +2,312 +Belgium +1,339 +1,554 +1,440 +Holland +1,051 +1,279 +1,183 +Other countries +9,699 +10,854 +11,018 +Total Diagnostics +$ +155,903 +$ +127,760 +$ +121,132 +Year Ended September 30, +2022 +2021 +2020 +South Korea +$ +33,642 +$ +9,242 +$ +1,908 +U.S. and territories +32,450 +44,785 +36,689 +Germany +17,969 +18,460 +14,190 +China +15,368 +13,559 +19,047 +United Kingdom +12,882 +13,097 +14,765 +France +11,948 +10,733 +5,579 +Spain +11,134 +12,593 +7,242 +Finland +10,317 +17,936 +2,518 +Turkey +7,858 +7,281 +2,819 +Japan +6,591 +6,532 +3,707 +Australia +4,312 +9,115 +5,957 +Italy +3,735 +7,516 +4,067 +Czech Republic +1,926 +922 +601 +India +1,257 +5,558 +2,099 +Switzerland +1,119 +632 +758 +Other countries +4,607 +12,175 +10,589 +Total Life Science +$ +177,115 +$ +190,136 +$ +132,535 +- +72 +- +Table of Contents +In locations outside the U.S., the Company’s identifiable assets were concentrated as follows at the end of the most recent fiscal years, with no additional country’s total of assets exceeding $ 5,000 : +As of September 30, +2022 +2021 +Israel +$ +71,536 +$ +80,416 +United Kingdom +27,927 +30,027 +Germany +16,734 +22,293 +Canada +15,875 +15,236 +Italy +7,225 +6,921 +(16) +Commitments and Contingent Obligations +(a) +Royalty Commitments +- +We have entered into various license agreements that require payment of royalties based on a specified percentage of net revenues from licensed products, with such percentages generally ranging from approximately 3 % to 10 %. During the year ended September 30, 2022, royalty expense associated with these agreements totaled approximately $ 2,300 , with 40 % and 60 % of such expense relating to our Diagnostics and Life Science segments, respectively. These royalty expenses are recognized as the related revenues are earned and are recorded as a component of cost of sales. Annual royalty expenses associated with these agreements totaled approximately $ 5,200 and $ 1,900 for the years ended September 30, 2021 and 2020, respectively, with the Diagnostics/Life Science segment split of such net revenues equating to approximately 25 / 75 and 80 / 20 in each of these years, respectively. +(b) +Purchase Commitments +- Excluding the operating lease commitments reflected in Note 9, we have purchase commitments primarily for inventories and service items as part of the normal course of business. Commitments made under these obligations are $ 40,182 for fiscal 2023 and $ 1,109 for fiscal 2024 through fiscal 2026. No purchase commitments have been made beyond fiscal 2026. +(c) +Litigation +- We are a party to various litigation matters from time to time that we believe are in the normal course of business. The ultimate resolution of these routine matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. Additionally, the Company has also become a party to certain legal matters that are outside the normal course of business. See Note 5 for a discussion of Magellan’s DOJ LeadCare legal matter. +(d) +Indemnifications +- In conjunction with certain contracts and agreements, we provide routine indemnifications related to our performance obligations. The terms of these indemnifications range in duration and in some circumstances are not explicitly defined. The maximum obligation under some such indemnifications is not explicitly stated and, as a result of our having no history of paying such indemnifications, cannot be reasonably estimated. We have no t made any payments for these indemnifications and no liability is recorded at September 30, 2022 or 2021. +(17) +Pending Merger +On July 7, 2022, the Company entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “Merger Agreement”) with SD Biosensor, Inc., a corporation with limited liability organized under the laws of the Republic of Korea (“SDB”), Columbus Holding Company, a Delaware corporation (“Parent”), and Madeira Acquisition Corp., an Ohio corporation and a direct wholly owned subsidiary of Parent (“Merger Sub”). Meridian is informed that SJL Partners, LLC (“SJL”) is currently the sole shareholder of Parent, and SDB together with SJL will be the sole shareholders of Parent as of the closing of the Merger. Pursuant to the Merger Agreement, Merger Sub will merge with and into Meridian (the “Merger”), with Meridian surviving the Merger as a direct wholly owned subsidiary of Parent. +At the effective time of the proposed Merger (the “Effective Time”), each share of common stock, no par value per share, of the Company issued and outstanding as of immediately prior to the Effective Time (other than dissenting shares or shares of the Company’s common stock held by the Company as treasury stock or owned by SDB, Merger Sub or any subsidiary of the Company or SDB) will be cancelled and cease to exist and automatically convert into the right to receive cash in an amount equal to $ 34.00 , without interest. +- +73 +- +Table of Contents +Consummation of the Merger is subject to customary closing conditions, including, without limitation: (i) the absence of certain legal impediments; and (ii) the condition that no Specified Outcome, as such term is defined in the Merger Agreement, related to the DOJ LeadCare legal matter (which is described in the section entitled “Legal Matter Relating to LeadCare Product Line” of Item 3. “Legal Proceedings”) has occurred or is reasonably likely to occur. +On November 21, 2022, the parties received clearance from the Committee on Foreign Investment in the United States with respect to the Merger and the transactions contemplated by the Merger Agreement. +The Merger Agreement contains certain termination rights for the Company and SDB. In addition to the foregoing termination right, and subject to certain limitations: (i) the Company or SDB may terminate the Merger Agreement if the Merger is not consummated by January 6, 2023; and (ii) the Company and SDB may mutually agree to terminate the Merger Agreement. +The Company incurred transaction related costs of approximately $ 6,800 during the year ended September 30, 2022 related to the Merger, which is recorded in acquisition and transaction related costs in the Consolidated +Statements of Operations. +(18) +Subsequent Event +On October 26, 2022, Meridian acquired select assets from Estel Biosciences, Inc., as part of Meridian’s continued investment in its immunological research and development capabilities. Among other assets, the Company acquired intellectual property that will be incorporated into the Life Science operations in North Brunswick, New Jersey and Memphis, Tennessee for the design and manufacture of recombinant proteins using an insect cell expression system. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE +Not applicable. +ITEM 9A. +CONTROLS AND PROCEDURES +As of September 30, 2022, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of September 30, 2022. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2022. +Our internal control report is included in this Form 10-K after Item 8, under the caption “Management’s Report on Internal Control over Financial Reporting.” +- 74 - +Table of Contents +ITEM 9B. +OTHER INFORMATION +Not applicable. +ITEM 9C. +DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS +None. +PART III. +The information required by Items 10, 11, 12, 13 and 14 of Part III will be provided within a separate filing within 120 days of the Company’s September 30, 2022 fiscal year end and is incorporated herein by reference. Portions of the Proxy Statement related to the proposed Merger filed on September 8, 2022 are incorporated by reference in Part III of this report. +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) +(1) and (2) FINANCIAL STATEMENTS AND SCHEDULES. +All financial statements and schedules required to be filed by Item 8 of this Form and included in this report have been so identified under Item 8. No additional financial statements or schedules are being filed since the requirements of paragraph (c) under Item 15 are not applicable to Meridian. +(b) +(3) EXHIBITS. +Exhibit +Number +Description of Exhibit +2.1 +Agreement and Plan of Merger, dated as of July 7, 2022, by and among Meridian, SD Biosensor, Inc., Columbus Holding Company, and Madeira Acquisition Corp. (Incorporated by reference to Meridian’s Form 8-K filed with the Securities and Exchange Commission (“SEC”) on July 7, 2022) +3.1 +Amended Articles of Incorporation (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 26, 2019) +3.2 +Amended and Restated Code of Regulations (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 26, 2019) +4.1 +Description of Securities (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 26, 2019) +10.1* +Amendment No. 1 to Supplemental Benefit Agreement Dated September 23, 2014 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on September 25, 2014) +10.2* +Third Amended and Restated Employment Agreement Dated October 3, 2016 between Meridian and John A. Kraeutler (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on October 5, 2016) +10.3* +Amended and Restated Employment Agreement dated effective October 1, 2019 between Meridian and John P. Kenny (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on November 7, 2019) +10.4* +2012 Stock Incentive Plan, effective January 25, 2012 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2011) +10.5* +Israeli Appendix to the Meridian Bioscience, Inc. 2012 Stock Incentive Plan dated effective July 10, 2020 (Incorporated by reference to Meridian’s Annual Report on Form 10-K for the Fiscal Year Ended September 30, 2020) +- 75 - +Table of Contents +10.6* +Meridian Bioscience, Inc. 2021 Omnibus Award Plan (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2021) +10.7* +Form of Time-Based Restricted Share Unit Award Agreement (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 23, 2021) +10.8* +Form of Nonqualified Stock Option Agreement (Incorporated by reference to Meridian’s Form 10-K filed with the SEC on November 23, 2021) +10.9*† +Form of Performance-Based Restricted Share Unit Award Agreement (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2021) +10.10*† +Chief Executive Officer Cash-Based Incentive Compensation Plan for Fiscal Year 2022 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2021) +10.11*† +Executive Vice President Cash-Based Incentive Compensation Plan for Fiscal Year 2022 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended December 31, 2021) +10.12* +Form of Meridian Bioscience, Inc. Change in Control Agreement dated August 4, 2016 (Incorporated by reference to Meridian’s Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2016) +10.13 +Amended and Restated Credit Agreement, dated as of October 25, 2021, by and among Meridian Bioscience, Inc., as Borrower, the Guarantors party thereto, the Lenders party thereto, PNC Bank, National Association, as administrative agent, PNC Capital Markets LLC, as joint lead arranger and sole bookrunner, and Fifth Third Bank, National Association, as joint lead arranger and syndication agent (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on October 29, 2021) +10.14* +Offer Letter, dated February 8, 2022, between Meridian and Andrew Kitzmiller (Incorporated by reference to Meridian’s Form 8-K filed with the SEC on February 21, 2022) +10.15 +Form of Indemnification Agreement (Incorporated by reference to Meridian’s Current Report on Form 8-K filed with the SEC on July 7, 2022) +21 +List of Subsidiaries of the Registrant (Filed herewith) +23.1 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +23.2 +Consent of Independent Registered Public Accounting Firm (Filed herewith) +31.1 +Certification of Principal Executive Officer required by Rule 13a-14(a) (Filed herewith) +31.2 +Certification of Principal Financial Officer required by Rule 13a-14(a) (Filed herewith) +32** +Section 1350 Certification of Chief Executive Officer and Chief Financial Officer (Furnished herewith) +101.INS*** +Inline XBRL Instance Document +101.SCH*** +Inline XBRL Taxonomy Extension Schema +- 76 - +Table of Contents +101.CAL*** +Inline XBRL Taxonomy Extension Calculation Linkbase +101.DEF*** +Inline XBRL Taxonomy Extension Definition Linkbase +101.LAB*** +Inline XBRL Taxonomy Extension Label Linkbase +101.PRE*** +Inline XBRL Taxonomy Extension Presentation Linkbase +104*** +Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) +* +Management Compensatory Contracts +** +Furnished, not filed +*** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. +† +Schedules to and certain portions of these exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The omitted information is not material and would likely cause competitive harm to the Registrant if publicly disclosed. The Registrant hereby agrees to furnish a copy of any omitted schedule or other portion to the SEC upon request. +Meridian will provide shareholders with any exhibit upon the payment of a specified reasonable fee, which fee shall be limited to Meridian’s reasonable expenses in furnishing such exhibit. +ITEM 16. +FORM 10-K SUMMARY +Not applicable. +- 77 - +Table of Contents +SIGNATURES +Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +MERIDIAN BIOSCIENCE, INC. +By: +/s/ Jack Kenny +Date: November 22, 2022 +Jack Kenny +Chief Executive Officer +We, the undersigned directors and officers of the Registrant, hereby severally constitute Jack Kenny and Andrew S. Kitzmiller, and each of them singly, our true and lawful attorneys with full power to them and each of them to sign for us, in our names in the capacities indicated below, any and all amendments to the Annual Report on Form 10-K filed with the Securities and Exchange Commission. +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. +Signature +Capacity +Date +/s/ Jack Kenny +Chief Executive Officer and Director +November 22, 2022 +Jack Kenny +/s/ Andrew S. Kitzmiller +Executive Vice President and Chief +November 22, 2022 +Andrew S. Kitzmiller +Financial Officer (Principal Financial Officer) +/s/ Julie Smith +Senior Vice President and Controller +November 22, 2022 +Julie Smith +(Principal Accounting Officer) +/s/ John C. McIlwraith +Chairman of the Board +November 22, 2022 +John C. McIlwraith +/s/ James M. Anderson +Director +November 22, 2022 +James M. Anderson +/s/ Anthony P. Bihl III +Director +November 22, 2022 +Anthony P. Bihl III +/s/ Dwight E. Ellingwood +Director +November 22, 2022 +Dwight E. Ellingwood +/s/ John M. Rice, Jr. +Director +November 22, 2022 +John M. Rice, Jr. +/s/ Catherine A. Sazdanoff +Director +November 22, 2022 +Catherine A. Sazdanoff +/s/ Felicia Williams +Director +November 22, 2022 +Felicia Williams +- 78 - +Table of Contents +SCHEDULE II +Meridian Bioscience, Inc. +and Subsidiaries +Valuation and Qualifying Accounts +(Dollars in thousands) +Years Ended September 30, 2022, 2021 and 2020 +Description +Balance at +Beginning +of Period +Charged to +Costs and +Expenses +Deductions +Other (a) +Balance at +End of +Period +Year Ended September 30, 2022: +Allowance for doubtful accounts +$ +1,078 +$ +946 +$ +( 662 +) +$ +( 37 +) +$ +1,325 +Inventory realizability reserves +4,997 +5,121 +( 3,882 +) +( 104 +) +6,132 +Valuation allowances – deferred taxes +1,624 +666 +( 760 +) +( 103 +) +1,427 +Year Ended September 30, 2021: +Allowance for doubtful accounts +$ +513 +$ +583 +$ +( 34 +) +$ +16 +$ +1,078 +Inventory realizability reserves +3,629 +2,703 +( 1,297 +) +( 38 +) +4,997 +Valuation allowances – deferred taxes +895 +729 +— +— +1,624 +Year Ended September 30, 2020: +Allowance for doubtful accounts +$ +537 +$ +34 +$ +( 75 +) +$ +17 +$ +513 +Inventory realizability reserves +2,441 +1,775 +( 564 +) +( 23 +) +3,629 +Valuation allowances – deferred taxes +666 +335 +( 106 +) +— +895 +(a) +Balances reflect the effects of currency translation. +- 79 - \ No newline at end of file diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/filing_metadata.csv b/raw/filings/0000794172/2022/0001193125-22-290521/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..1082d23cc12c089dcfdae5941922844ca5b41b1c --- /dev/null +++ b/raw/filings/0000794172/2022/0001193125-22-290521/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000794172,VIVO,MERIDIAN BIOSCIENCE INC,10-K,2022-11-22,2022-09-30,2022-11-22T13:27:38.000Z,0001193125-22-290521,d384542d10k.htm,10-K,10762042,1,1,https://www.sec.gov/Archives/edgar/data/794172/000119312522290521/d384542d10k.htm,https://www.sec.gov/Archives/edgar/data/794172/000119312522290521/,2022,2022,1 diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/item1.txt b/raw/filings/0000794172/2022/0001193125-22-290521/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..a7e0d0c51b1dbd97e4f10bf0b850d24a9c5112cf --- /dev/null +++ b/raw/filings/0000794172/2022/0001193125-22-290521/item1.txt @@ -0,0 +1,14 @@ +ITEM 1. +BUSINESS +Overview +Meridian is a fully-integrated life science company with principal businesses in: (i) the development, manufacture, sale and distribution of diagnostic testing systems and kits, primarily for certain gastrointestinal and respiratory infectious diseases, and elevated blood lead levels; and (ii) the manufacture and distribution of bulk antigens, antibodies, immunoassay blocking reagents, specialized Polymerase Chain Reaction (“PCR”) master mixes, and bioresearch reagents used by other diagnostic test manufacturers and researchers in immunological and molecular tests for human, animal, plant and environmental applications. +Our website is www.meridianbioscience.com . We make available our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statements and any amendments thereto, free of charge through this website, as soon as reasonably practicable after such material has been electronically filed with or furnished to the SEC. The SEC maintains an internet site containing these filings and other information regarding Meridian at www.sec.gov . The information on our website is not and should not be considered part of this Form 10-K. +Pending Merger +On July 7, 2022, the Company entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “Merger Agreement”) with SD Biosensor, Inc., a corporation with limited liability organized under the laws of the Republic of Korea (“SDB”), Columbus Holding Company, a Delaware corporation (“Parent”), and Madeira Acquisition Corp., an Ohio corporation and a direct wholly owned subsidiary of Parent (“Merger Sub”). Meridian is informed that SJL Partners, LLC (“SJL”) is currently the sole shareholder of Parent, and SDB together with SJL will be the sole shareholders of Parent as of the closing of the Merger. Pursuant to the Merger Agreement, Merger Sub will merge with and into Meridian (the “Merger”), with Meridian surviving the Merger as a direct wholly owned subsidiary of Parent. Consummation of the Merger is subject to customary closing conditions, including, without limitation: (i) the absence of certain legal impediments; and (ii) the condition that no Specified Outcome, as such term is defined in the Merger Agreement, related to the DOJ LeadCare legal matter (which is described in the section entitled “Legal Matter Relating to LeadCare Product Line” of Item 3. “Legal Proceedings”) has occurred or is reasonably likely to occur. +On November 21, 2022, the parties received clearance from the Committee on Foreign Investment in the United States with respect to the Merger and the transactions contemplated by the Merger Agreement. +The foregoing description of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Merger Agreement, which is attached as an exhibit to our Current Report on Form 8-K filed with the SEC on July 7, 2022. +Reportable Segments +Our reportable segments are Diagnostics and Life Science, both of which are headquartered in Cincinnati, Ohio. We describe these reportable segments in this “Business” section and in other locations in this report: +Type of Segment Information +Location within Form 10-K +Physical locations and activities \ No newline at end of file diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/item13.txt b/raw/filings/0000794172/2022/0001193125-22-290521/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..762c3fdea3d1c31cc989f68da8ad2f01f0ffb582 --- /dev/null +++ b/raw/filings/0000794172/2022/0001193125-22-290521/item13.txt @@ -0,0 +1,3 @@ +Item 13 +Certain Relationships and Related Transactions, and Director Independence +75 \ No newline at end of file diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/item9a.txt b/raw/filings/0000794172/2022/0001193125-22-290521/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..9e798a7dbda29caf400bc915bac1e5b71249b98b --- /dev/null +++ b/raw/filings/0000794172/2022/0001193125-22-290521/item9a.txt @@ -0,0 +1,6 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +As of September 30, 2022, an evaluation was completed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) and 15d-15(b) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of September 30, 2022. There have been no changes in our internal control over financial reporting identified in connection with the evaluation of internal control that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, or in other factors that could significantly affect internal control subsequent to September 30, 2022. +Our internal control report is included in this Form 10-K after Item 8, under the caption “Management’s Report on Internal Control over Financial Reporting.” +- 74 - +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/rp_note.txt b/raw/filings/0000794172/2022/0001193125-22-290521/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000794172/2022/0001193125-22-290521/rpt_disclosure.txt b/raw/filings/0000794172/2022/0001193125-22-290521/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/filing.txt b/raw/filings/0001116463/2019/0001564590-20-008195/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e77703b34d2d30678a840daf5b68132e59500981 --- /dev/null +++ b/raw/filings/0001116463/2019/0001564590-20-008195/filing.txt @@ -0,0 +1,5467 @@ +osur-10k_20191231.htm +false +FY +OSUR +0001116463 +--12-31 +Large Accelerated Filer +P20Y +P2Y +P2Y +P2Y +P30D +true +true +P10Y +P1Y +P3Y +P10Y +P10Y +P8Y4M2D +P10Y +P9Y +P10Y +P10Y +P7Y +P5Y +P10Y +P15Y +P10Y +P10Y +P7Y +P15Y +P5Y2M15D +P3Y5M12D +P5Y +P6Y +P7Y +P5Y10M20D +P5Y10M20D +P4Y11M26D +P4Y7M6D +P6Y1M6D +P8Y1M6D +P5Y10M24D +5.37 +8.87 +16.80 +8.24 +14.95 +21.89 +0001116463 +2019-01-01 +2019-12-31 +xbrli:shares +0001116463 +2020-02-29 +iso4217:USD +0001116463 +2019-06-30 +0001116463 +2019-12-31 +0001116463 +2018-12-31 +iso4217:USD +xbrli:shares +0001116463 +osur:ProductAndServicesMember +2019-01-01 +2019-12-31 +0001116463 +osur:ProductAndServicesMember +2018-01-01 +2018-12-31 +0001116463 +osur:ProductAndServicesMember +2017-01-01 +2017-12-31 +0001116463 +osur:OtherRevenuesMember +2019-01-01 +2019-12-31 +0001116463 +osur:OtherRevenuesMember +2018-01-01 +2018-12-31 +0001116463 +osur:OtherRevenuesMember +2017-01-01 +2017-12-31 +0001116463 +2018-01-01 +2018-12-31 +0001116463 +2017-01-01 +2017-12-31 +0001116463 +us-gaap:CommonStockMember +2016-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2016-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2016-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2016-12-31 +0001116463 +2016-12-31 +0001116463 +us-gaap:CommonStockMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:CommonStockMember +2017-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2017-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2017-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2017-12-31 +0001116463 +2017-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:CommonStockMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:CommonStockMember +2018-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2018-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2018-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2018-12-31 +0001116463 +us-gaap:CommonStockMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:CommonStockMember +2019-12-31 +0001116463 +us-gaap:AdditionalPaidInCapitalMember +2019-12-31 +0001116463 +us-gaap:AccumulatedOtherComprehensiveIncomeMember +2019-12-31 +0001116463 +us-gaap:RetainedEarningsMember +2019-12-31 +0001116463 +us-gaap:AccountingStandardsUpdate201409Member +2019-01-01 +2019-12-31 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +2019-01-01 +2019-12-31 +0001116463 +osur:DiversigenIncMember +2019-01-01 +2019-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockUnitMember +2019-01-01 +2019-12-31 +osur:Segment +0001116463 +osur:GuaranteedInvestmentCertificatesMember +2019-12-31 +0001116463 +osur:CorporateBondsMember +2019-12-31 +0001116463 +osur:GuaranteedInvestmentCertificatesMember +2018-12-31 +0001116463 +osur:CorporateBondsMember +2018-12-31 +0001116463 +osur:MaturityOfAvailableForSaleSecurityLessThanOneYearMember +2019-12-31 +0001116463 +osur:MaturityOfAvailableForSaleSecurityGreaterThanOneYearMember +2019-12-31 +0001116463 +srt:MinimumMember +us-gaap:BuildingMember +2019-01-01 +2019-12-31 +0001116463 +srt:MaximumMember +us-gaap:BuildingMember +2019-01-01 +2019-12-31 +0001116463 +srt:MinimumMember +us-gaap:ComputerEquipmentMember +2019-01-01 +2019-12-31 +0001116463 +srt:MaximumMember +us-gaap:ComputerEquipmentMember +2019-01-01 +2019-12-31 +0001116463 +srt:MinimumMember +us-gaap:MachineryAndEquipmentMember +2019-01-01 +2019-12-31 +0001116463 +srt:MaximumMember +us-gaap:MachineryAndEquipmentMember +2019-01-01 +2019-12-31 +0001116463 +srt:MinimumMember +us-gaap:FurnitureAndFixturesMember +2019-01-01 +2019-12-31 +0001116463 +srt:MaximumMember +us-gaap:FurnitureAndFixturesMember +2019-01-01 +2019-12-31 +0001116463 +srt:MinimumMember +2019-01-01 +2019-12-31 +0001116463 +srt:MaximumMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:AccountingStandardsUpdate201409Member +us-gaap:DifferenceBetweenRevenueGuidanceInEffectBeforeAndAfterTopic606Member +osur:DrugTestingKitSalesMember +2018-01-01 +osur:PerformanceObligation +0001116463 +us-gaap:AccountingStandardsUpdate201409Member +osur:DrugTestingKitSalesMember +2018-01-01 +0001116463 +us-gaap:DifferenceBetweenRevenueGuidanceInEffectBeforeAndAfterTopic606Member +us-gaap:AccountingStandardsUpdate201409Member +2018-01-01 +0001116463 +us-gaap:AccountingStandardsUpdate201409Member +2018-01-01 +0001116463 +us-gaap:UpFrontPaymentArrangementMember +2019-12-31 +0001116463 +us-gaap:UpFrontPaymentArrangementMember +2018-12-31 +0001116463 +us-gaap:LongTermContractWithCustomerMember +2019-12-31 +0001116463 +us-gaap:LongTermContractWithCustomerMember +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:OraquickMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:OraquickMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:OraquickMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:OrageneMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:OrageneMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:OrageneMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:ORAcollectMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:ORAcollectMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:ORAcollectMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:InterceptMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:InterceptMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:InterceptMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:MicrobiomeLaboratoryServicesMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:MicrobiomeLaboratoryServicesMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:MicrobiomeLaboratoryServicesMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:HistofreezerMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:HistofreezerMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:HistofreezerMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:OMNIGeneGUTMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:OMNIGeneGUTMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:OMNIGeneGUTMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +osur:OtherProductsMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +osur:OtherProductsMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +osur:OtherProductsMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:SalesMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:SalesMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:SalesMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:RoyaltyIncomeMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:RoyaltyIncomeMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:ResearchAndDevelopmentFundingMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:ResearchAndDevelopmentFundingMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:ResearchAndDevelopmentFundingMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:CharitableSupportReimbursementMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:CharitableSupportReimbursementMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:CharitableSupportReimbursementMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:OtherIncomeMember +osur:GrantFundingMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:OtherIncomeMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:OtherIncomeMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:OtherIncomeMember +2017-01-01 +2017-12-31 +0001116463 +country:US +2019-01-01 +2019-12-31 +0001116463 +country:US +2018-01-01 +2018-12-31 +0001116463 +country:US +2017-01-01 +2017-12-31 +0001116463 +srt:EuropeMember +2019-01-01 +2019-12-31 +0001116463 +srt:EuropeMember +2018-01-01 +2018-12-31 +0001116463 +srt:EuropeMember +2017-01-01 +2017-12-31 +0001116463 +osur:OtherForeignCountriesMember +2019-01-01 +2019-12-31 +0001116463 +osur:OtherForeignCountriesMember +2018-01-01 +2018-12-31 +0001116463 +osur:OtherForeignCountriesMember +2017-01-01 +2017-12-31 +xbrli:pure +0001116463 +osur:CustomerMember +us-gaap:AccountsReceivableMember +us-gaap:CustomerConcentrationRiskMember +2019-01-01 +2019-12-31 +0001116463 +osur:CustomerMember +us-gaap:AccountsReceivableMember +us-gaap:CustomerConcentrationRiskMember +2018-01-01 +2018-12-31 +0001116463 +osur:CustomerMember +us-gaap:SalesRevenueNetMember +us-gaap:CustomerConcentrationRiskMember +2019-01-01 +2019-12-31 +0001116463 +osur:CustomerMember +us-gaap:SalesRevenueNetMember +us-gaap:CustomerConcentrationRiskMember +2018-01-01 +2018-12-31 +0001116463 +osur:CustomerMember +us-gaap:SalesRevenueNetMember +us-gaap:CustomerConcentrationRiskMember +2017-01-01 +2017-12-31 +osur:Supplier +0001116463 +osur:DNAGenotekMember +2019-12-31 +0001116463 +2019-01-01 +0001116463 +osur:CommonStockOptionsUnvestedRestrictedStockAndUnvestedPerformanceUnitsMember +2019-01-01 +2019-12-31 +0001116463 +osur:CommonStockOptionsUnvestedRestrictedStockAndUnvestedPerformanceUnitsMember +2018-01-01 +2018-12-31 +0001116463 +osur:CommonStockOptionsUnvestedRestrictedStockAndUnvestedPerformanceUnitsMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:MoneyMarketFundsMember +us-gaap:FairValueInputsLevel1Member +2019-12-31 +0001116463 +us-gaap:MoneyMarketFundsMember +us-gaap:FairValueInputsLevel1Member +2018-12-31 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +2019-01-04 +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +2019-12-31 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +2019-10-31 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +srt:MaximumMember +2019-12-31 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +us-gaap:DevelopedTechnologyRightsMember +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +us-gaap:CustomerRelationshipsMember +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +us-gaap:TradeNamesMember +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +us-gaap:DevelopedTechnologyRightsMember +2019-01-04 +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +us-gaap:CustomerRelationshipsMember +2019-01-04 +2019-01-04 +0001116463 +osur:CorebiomeIncAndNovosanisNVMember +us-gaap:TradeNamesMember +2019-01-04 +2019-01-04 +0001116463 +osur:DiversigenIncMember +2019-11-08 +2019-11-08 +0001116463 +osur:DiversigenIncMember +2019-12-31 +0001116463 +osur:DiversigenIncMember +2019-11-08 +0001116463 +osur:DiversigenIncMember +us-gaap:CustomerRelationshipsMember +2019-11-08 +0001116463 +osur:DiversigenIncMember +us-gaap:TradeNamesMember +2019-11-08 +0001116463 +osur:DiversigenIncMember +us-gaap:CustomerRelationshipsMember +2019-11-08 +2019-11-08 +0001116463 +osur:DiversigenIncMember +us-gaap:TradeNamesMember +2019-11-08 +2019-11-08 +0001116463 +osur:CorebiomeIncDiversigenAndNovosanisNVMember +2019-01-01 +2019-12-31 +0001116463 +osur:CorebiomeIncDiversigenAndNovosanisNVMember +2018-01-01 +2018-12-31 +0001116463 +osur:CorebiomeIncDiversigenAndNovosanisNVMember +2017-01-01 +2017-12-31 +0001116463 +osur:CryosurgicalSystemsMember +2019-08-16 +0001116463 +osur:CryosurgicalSystemsMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:LandMember +2019-12-31 +0001116463 +us-gaap:LandMember +2018-12-31 +0001116463 +us-gaap:BuildingAndBuildingImprovementsMember +2019-12-31 +0001116463 +us-gaap:BuildingAndBuildingImprovementsMember +2018-12-31 +0001116463 +us-gaap:MachineryAndEquipmentMember +2019-12-31 +0001116463 +us-gaap:MachineryAndEquipmentMember +2018-12-31 +0001116463 +osur:ComputerEquipmentAndSoftwareMember +2019-12-31 +0001116463 +osur:ComputerEquipmentAndSoftwareMember +2018-12-31 +0001116463 +us-gaap:FurnitureAndFixturesMember +2019-12-31 +0001116463 +us-gaap:FurnitureAndFixturesMember +2018-12-31 +0001116463 +us-gaap:ConstructionInProgressMember +2019-12-31 +0001116463 +us-gaap:ConstructionInProgressMember +2018-12-31 +0001116463 +us-gaap:CustomerRelationshipsMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:IntellectualPropertyMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:DevelopedTechnologyRightsMember +srt:MinimumMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:TradeNamesMember +srt:MinimumMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:DevelopedTechnologyRightsMember +srt:MaximumMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:TradeNamesMember +srt:MaximumMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:CustomerRelationshipsMember +2019-12-31 +0001116463 +us-gaap:IntellectualPropertyMember +2019-12-31 +0001116463 +us-gaap:DevelopedTechnologyRightsMember +2019-12-31 +0001116463 +us-gaap:TradeNamesMember +2019-12-31 +0001116463 +us-gaap:CustomerRelationshipsMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:IntellectualPropertyMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:DevelopedTechnologyRightsMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:TradeNamesMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:CustomerRelationshipsMember +2018-12-31 +0001116463 +us-gaap:IntellectualPropertyMember +2018-12-31 +0001116463 +us-gaap:DevelopedTechnologyRightsMember +2018-12-31 +0001116463 +us-gaap:TradeNamesMember +2018-12-31 +0001116463 +osur:TwoThousandSeventeenFederalTaxReturnMember +2018-01-01 +2018-12-31 +0001116463 +osur:TwoThousandSeventeenFederalTaxReturnMember +2018-12-31 +0001116463 +2018-10-01 +2018-12-31 +0001116463 +osur:ExpirationPeriodTaxYear2030To2034Member +2019-12-31 +0001116463 +osur:ExpirationPeriodTaxYear2035To2037Member +2019-12-31 +0001116463 +osur:NonExpiringMember +2019-12-31 +0001116463 +us-gaap:AccountingStandardsUpdate201609Member +2017-01-01 +2017-01-01 +0001116463 +2017-01-01 +2017-01-01 +0001116463 +us-gaap:EmployeeStockOptionMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:EmployeeStockOptionMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:EmployeeStockOptionMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:EmployeeStockOptionMember +2019-12-31 +0001116463 +osur:RangeOneMember +2019-01-01 +2019-12-31 +0001116463 +osur:RangeTwoMember +2019-01-01 +2019-12-31 +0001116463 +osur:RangeThreeMember +2019-01-01 +2019-12-31 +0001116463 +osur:RangeOneMember +2019-12-31 +0001116463 +osur:RangeTwoMember +2019-12-31 +0001116463 +osur:RangeThreeMember +2019-12-31 +0001116463 +us-gaap:RestrictedStockMember +2019-01-01 +2019-12-31 +0001116463 +us-gaap:RestrictedStockMember +2018-01-01 +2018-12-31 +0001116463 +us-gaap:RestrictedStockMember +2017-01-01 +2017-12-31 +0001116463 +osur:RestrictedStockAwardAndRestrictedStockUnitsMember +2018-12-31 +0001116463 +osur:RestrictedStockAwardAndRestrictedStockUnitsMember +2019-01-01 +2019-12-31 +0001116463 +osur:RestrictedStockAwardAndRestrictedStockUnitsMember +2019-12-31 +0001116463 +us-gaap:RestrictedStockMember +2019-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockMember +us-gaap:ShareBasedCompensationAwardTrancheOneMember +2019-01-01 +2019-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockMember +us-gaap:ShareBasedCompensationAwardTrancheTwoMember +2019-01-01 +2019-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockUnitMember +2018-01-01 +2018-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockUnitMember +2017-01-01 +2017-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockUnitMember +2018-12-31 +0001116463 +osur:PerformanceBasedRestrictedStockUnitMember +2019-12-31 +0001116463 +2008-08-05 +0001116463 +osur:StockRepurchaseProgramMember +2019-01-01 +2019-12-31 +0001116463 +osur:StockRepurchaseProgramMember +2018-01-01 +2018-12-31 +0001116463 +osur:StockRepurchaseProgramMember +2017-01-01 +2017-12-31 +0001116463 +us-gaap:GeneralAndAdministrativeExpenseMember +2018-01-01 +2018-12-31 +0001116463 +osur:OSURMember +2019-01-01 +2019-12-31 +0001116463 +osur:OSURMember +2018-01-01 +2018-12-31 +0001116463 +osur:OSURMember +2017-01-01 +2017-12-31 +0001116463 +osur:DNAGMember +2019-01-01 +2019-12-31 +0001116463 +osur:DNAGMember +2018-01-01 +2018-12-31 +0001116463 +osur:DNAGMember +2017-01-01 +2017-12-31 +0001116463 +osur:OSURMember +2019-12-31 +0001116463 +osur:OSURMember +2018-12-31 +0001116463 +osur:DNAGMember +2019-12-31 +0001116463 +osur:DNAGMember +2018-12-31 +0001116463 +country:US +2019-12-31 +0001116463 +country:US +2018-12-31 +0001116463 +country:CA +2019-12-31 +0001116463 +country:CA +2018-12-31 +0001116463 +osur:OtherForeignCountriesMember +2019-12-31 +0001116463 +osur:OtherForeignCountriesMember +2018-12-31 +0001116463 +us-gaap:EmploymentContractsMember +2019-12-31 +0001116463 +osur:RegisteredRetirementSavingsPlanMember +osur:DNAGenotekMember +2019-01-01 +2019-12-31 +0001116463 +osur:RegisteredRetirementSavingsPlanMember +osur:DNAGenotekMember +2018-01-01 +2018-12-31 +0001116463 +osur:RegisteredRetirementSavingsPlanMember +osur:DNAGenotekMember +2017-01-01 +2017-12-31 +0001116463 +2019-01-01 +2019-03-31 +0001116463 +2019-04-01 +2019-06-30 +0001116463 +2019-07-01 +2019-09-30 +0001116463 +2019-10-01 +2019-12-31 +0001116463 +2018-01-01 +2018-03-31 +0001116463 +2018-04-01 +2018-06-30 +0001116463 +2018-07-01 +2018-09-30 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +(Mark One) +☒ +Annual report pursuant to Section 13 or 15( d ) of the Securities Exchange ACT OF 1934 +For the fiscal year ended December 31, 2019 +or +☐ +Transition report pursuant to Section 13 or 15( d ) of the Securities Exchange Act of 1934 +F or the transition period from to +Commission File No. 001-16537 +ORASURE TECHNOLOGIES, INC . +(Exact Name of Registrant as Specified in Its Charter) +Delaware +36-4370966 +(State or Other Jurisdiction of +Incorporation or Organization) +(I.R.S. Employer +Identification No.) +220 East First Street +Bethlehem , Pennsylvania +18015 +(Address of Principal Executive Offices) +(Zip Code) +( 610 ) 882-1820 +(Registrant’s Telephone Number, Including Area Code): +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, $0.000001 par value per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +☒ +Accelerated filer +☐ +Non-accelerated filer +☐ +Smaller reporting company +☐ +Emerging Growth Company +☐ +If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by nonaffiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the Registrant’s most recently completed second fiscal quarter (June 30, 2019) : $ 569,761,924 +Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of February 21, 2020: 62,002,705 shares. +Documents Incorporated by Reference: +Portions of the Registrant’s Definitive Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference into Part III of this Annual Report. +Table of Contents +PART I +Page +ITEM 1. +Business +2 +ITEM 1A. +Risk Factors +20 +ITEM 1B. +Unresolved Staff Comments +45 +ITEM 2. +Properties +45 +ITEM 3. +Legal Proceedings +45 +ITEM 4. +Mine Safety Disclosures +45 +PART II +ITEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +46 +ITEM 6. +Selected Consolidated Financial Data +48 +ITEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +49 +ITEM 7A. +Quantitative and Qualitative Disclosures About Market Risk +62 +ITEM 8. +Financial Statements and Supplementary Data +62 +ITEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +62 +ITEM 9A. +Controls and Procedures +62 +ITEM 9B. +Other Information +64 +PART III +ITEM 10. +Directors, Executive Officers and Corporate Governance +65 +ITEM 11. +Executive Compensation +65 +ITEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +65 +ITEM 13. +Certain Relationships and Related Transactions, and Director Independence +65 +ITEM 14. +Principal Accountant Fees and Services +65 +PART IV +ITEM 15. +Exhibits and Consolidated Financial Statement Schedules +66 +ITEM 16. +Form 10-K Summary +68 +This Report contains certain “forward-looking statements,” within the meaning of the Federal securities laws. These may include statements about our expected revenues, earnings, losses, expenses or other financial performance, future product performance or development, expected regulatory filings and approvals, planned business transactions, expected manufacturing performance, views of future industry, competitive or market conditions, and other factors that could affect our future operations, results of operations or financial position. These statements often include words, such as “believes,” “expects,” “anticipates,” “intends,” “plans,” “estimates,” “may,” “will,” “should,” “could,” or similar expressions. +Forward-looking statements are not guarantees of future performance or results. Known and unknown factors that could cause actual performance or results to be materially different from those expressed or implied in these statements include, but are not limited to: ability to successfully manage and integrate acquisitions of other companies in a manner that complements or leverages our existing business, or otherwise expands or enhances our portfolio of products and our end-to-end service offerings, and the diversion of management’s attention from our ongoing business and regular business responsibilities to effect such integration; the expected economic benefits of acquisitions (and increased returns for our stockholders), including that the anticipated synergies, revenue enhancement strategies and other benefits from the acquisitions may not be fully realized or may take longer to realize than expected and our actual integration costs may exceed our estimates; impact of increased or different risks arising from the acquisition of companies located in foreign countries; ability to market and sell products, whether through our internal, direct sales force or third parties; impact of significant customer concentration in the genomics business; failure of distributors or other customers to meet purchase forecasts, historic purchase levels or minimum purchase requirements for our products; ability to manufacture products in accordance with applicable specifications, performance standards and quality requirements; ability to obtain, and timing and cost of obtaining, necessary regulatory approvals for new products or new indications or applications for existing products; ability to comply with applicable regulatory requirements; ability to effectively resolve warning letters, audit observations and other findings or comments from the U.S. Food and Drug Administration (“FDA”) or other regulators; changes in relationships, including disputes or disagreements, with strategic partners or other parties and reliance on strategic partners for the performance of critical activities under collaborative arrangements; ability to meet increased demand for the Company’s products; impact of replacing distributors; inventory levels at distributors and other customers; ability of the Company to achieve its financial and strategic objectives and continue to increase its revenues, including the ability to expand international sales; ability to identify, complete, integrate and realize the full benefits of future acquisitions; impact of competitors, competing products and technology changes; reduction or deferral of public funding available to customers; competition from new or better technology or lower cost products; ability to develop, commercialize and market new products; market acceptance of oral fluid or urine testing, collection or other products; market acceptance and uptake of microbiome informatics, microbial genetics technology and related analytics services; changes in market acceptance of products based on product performance or other factors, including changes in testing guidelines, algorithms or other recommendations by the Centers for Disease Control and Prevention (“CDC”) or other agencies; ability to fund research and development and other products and operations; ability to obtain and maintain new or existing product distribution channels; reliance on sole supply sources for critical products and components; availability of related products produced by third parties or products required for use of our products; impact of contracting with the U.S. government; impact of negative economic conditions; ability to maintain sustained profitability; ability to utilize net operating loss carry forwards or other deferred tax assets; volatility of the Company’s stock price; uncertainty relating to patent protection and potential patent infringement claims; uncertainty and costs of litigation relating to patents and other intellectual property; availability of licenses to patents or other technology; ability to enter into international manufacturing agreements; obstacles to international marketing and manufacturing of products; ability to sell products internationally, including the impact of changes in international funding sources and testing algorithms; adverse movements in foreign currency exchange rates; loss or impairment of sources of capital; ability to attract and retain qualified personnel; exposure to product liability and other types of litigation; changes in international, federal or state laws and regulations; customer consolidations and inventory practices; equipment failures and ability to obtain needed raw materials and components; the impact of terrorist attacks and civil unrest; and general political, business and economic conditions. These and other factors that could affect our results are discussed more fully under Item 1A, entitled “Risk Factors,” and elsewhere in this Annual Report. Although forward-looking statements help to provide information about future prospects, readers should keep in mind that forward-looking statements may not be reliable. Readers are cautioned not to place undue reliance on the forward-looking statements. The forward-looking statements are made as of the date of this Annual Report and we undertake no duty to update these statements. +Investors should also be aware that while we do, from time to time, communicate with securities analysts, it is against our policy to disclose any material non-public information or other confidential commercial information. Accordingly, stockholders should not assume that we agree with any statement or report issued by any analyst irrespective of the content of the statement or report. Furthermore, we have a policy against issuing or confirming financial forecasts or projections issued by others. Thus, to the extent that reports issued by securities analysts contain any projections, forecasts or opinions, such reports are not the responsibility of OraSure. +References in this Annual Report to “OraSure” mean OraSure Technologies, Inc. References in this Annual Report to “we,” “us,” “our,” or the “Company” mean OraSure and its consolidated subsidiaries, unless otherwise indicated. +1 +PART I +ITEM 1. +Business. +The overall goal of our Company is to empower the global community to improve health and wellness by providing access to accurate essential information. Our business is made up of two principal segments. The first is our “OSUR” business, which consists of the development, manufacture, marketing and sale of oral fluid diagnostic products and specimen collection devices using our proprietary technologies, as well as other diagnostic products including immunoassays and other in vitro diagnostic tests that are used on other specimen types. Our diagnostic products include tests for diseases including HIV and Hepatitis C that are performed on a rapid basis at the point of care and tests that are processed in a laboratory. These products are sold in the United States and internationally to various clinical laboratories, hospitals, clinics, community-based organizations and other public health organizations, distributors, government agencies, physicians’ offices, and commercial and industrial entities. Our HIV product is also sold in a consumer-friendly format in the over-the-counter (“OTC”) market in the U.S. and as a self-test to individuals in a number of other countries. +The second segment is our “DNAG” or molecular products and services business and is operated primarily through our subsidiaries, DNA Genotek Inc. (“DNAG”), a company based in Ottawa, Canada, CoreBiome, Inc. (“CoreBiome”), Diversigen, Inc. (“Diversigen”) and Novosanis NV (“Novosanis”). In the DNAG business, we manufacture and sell kits that are used to collect, stabilize, transport and store biological samples of genetic material for molecular testing. Our products are used for academic research and commercial applications, including ancestry, disease risk management, lifestyle and animal testing. Included in the disease risk management area are pharmacogenomics testing, hereditary disease screening, prenatal or cancer screening, population health initiatives and other molecular testing using DNA or RNA for diagnosis of acute disease. Our Oragene ® DNA sample collection kit provides an all-in-one system for the collection, stabilization, transportation and storage of DNA from human saliva. We also sell research use only collection products into the microbiome market. We offer our customers a suite of genomics and microbiome services that range from package customization and study design optimization to extraction, analysis and reporting services. The microbiome laboratory and bioinformatics services are provided by CoreBiome and Diversigen. Novosanis manufactures and sells the Colli-Pee ® collection device for the volumetric collection of first-void urine for use in research, screening and diagnostics in the liquid biopsy and sexually transmitted infection markets. Our DNAG business serves customers in many countries worldwide, including many leading research universities and hospitals. +OraSure was formed in May 2000 under Delaware law solely for the purposes of combining two companies, STC Technologies, Inc. (“STC Technologies”) and Epitope, Inc. (“Epitope”), and changing the state of incorporation of Epitope from Oregon to Delaware. STC Technologies and Epitope were merged into OraSure on September 29, 2000. Our principal offices are located at 220 East First Street, Bethlehem, Pennsylvania 18015, and our telephone number is (610) 882-1820. +Additional information about us can be found on our website, www.orasure.com . We make available free of charge through a link provided at such website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and our other filings with the Securities and Exchange Commission (“SEC”), as well as any amendments to those Reports and filings. These Reports and filings are made available as soon as reasonably practicable after they are filed with or furnished to the SEC. Our website and the information contained in or connected to that website are not intended to be incorporated by reference into this Annual Report. +2019 Developments +In early January 2019, we acquired two privately-held, early-stage companies, CoreBiome and Novosanis, in order to add differentiated products and services to the molecular collection systems segment of our business. +CoreBiome, a spin-off from the University of Minnesota, is based in St. Paul, Minnesota and provides microbiome laboratory and analytical services that can accelerate research and discovery for customers in the pharmaceutical, agricultural and academic research communities. CoreBiome was co-founded in 2016 by Dr. Dan Knights, a globally-recognized expert in microbiome informatics who has developed leading methods for analyzing microbiome data, along with Dr. Daryl Gohl and Dr. Kenny Beckman, domain experts in microbiome sample processing and analysis. +Novosanis is a Belgian company that was founded in 2013 as a spin-off from the University of Antwerp, Belgium. Novosanis is an early commercial stage producer and distributor of urine sample collection devices targeting the liquid biopsy and sexually transmitted infection screening markets. Novosanis’ primary product is Colli-Pee, an easy to use device designed for the standardized collection of first-void urine which can be used in the privacy of the user’s home or in a clinic. Product validation and clinical trials are also under way with various sexually transmitted infection test manufacturers. +2 +I n August 2019, we sold our cryosurgical systems line of business to a third party . This line of business consisted of medical devices used for the removal of benign skin lesions by cryosurgery or freezing. +In November 2019, we acquired another microbiome laboratory services provider, Diversigen. Based in Houston, Texas, Diversigen provides science-driven, customized solutions for metagenomics sequencing, bioinformatics, and statistical analysis for the study of the microbiome. The company was founded in 2013 by Dr. Joseph Petrosino, director of the Alkek Center for Metagenomics and Microbiome Research at the Baylor College of Medicine (“BCM”), where Diversigen was a BCM portfolio company. Diversigen was the first company to establish microbiome protocols in accordance with College of American Pathologists (“CAP”) accreditation and Clinical Laboratory Improvements Amendments of 1988 (“CLIA”) guidelines. +OSUR Segment Products +The following is a summary of our principal products for the infectious disease and risk management markets, which comprise the OSUR segment of our business: +OraQuick ® Rapid HIV Test +OraQuick ® is our rapid point-of-care test platform designed to test oral fluid, whole blood (i.e., both finger-stick and venous), plasma and serum samples for the presence of various antibodies or analytes. The device uses a porous flat pad to collect an oral fluid specimen. After collection, the pad is inserted into a vial containing a pre-measured amount of developer solution and allowed to develop. When blood, plasma or serum is to be tested, a loop collection device is used to collect a drop of the specimen and mix it in the developer solution, after which the collection pad is inserted into the solution and allowed to develop. In all cases, the specimen and developer solution then flow through the testing device where test results are observable in approximately 20 minutes. The OraQuick ® device is a screening test and generally requires a confirmation test where an initial positive result is obtained. +This product is sold under the OraQuick ADVANCE ® name in North America, Europe and certain other countries and under the OraQuick ® name in other developing countries. The test has received pre-market approval (“PMA”) from the FDA for the detection of antibodies to both HIV-1 and HIV-2 in oral fluid, finger-stick whole blood, venous whole blood and plasma. This test is available for use by laboratories located in the United States certified under the Clinical Laboratory Improvements Amendment of 1988 (“CLIA”), to perform moderately complex tests. We have also received a CLIA waiver for use of the test with oral fluid and finger-stick and venous whole blood. As a result, the test can be used by numerous additional sites in the United States not certified under CLIA to perform moderately complex tests, such as outreach clinics, community-based organizations and physicians’ offices. +On the international front, we have obtained a CE mark for our OraQuick ADVANCE ® test so that we can sell this product in Europe and other countries accepting the CE mark for commercialization and this product is registered for sale in other countries. We have distributors in place for several countries and are seeking to increase awareness and expand our distribution network for this product throughout the world. We have also received World Health Organization (“WHO”) pre-qualification for our export-only version of this product. +OraQuick ® In-Home HIV Test +The OraQuick ® In-Home HIV test is an OTC oral-fluid only version of our OraQuick ADVANCE ® HIV 1/2 Antibody Test. We received PMA approval to sell this test in the U.S. OTC market. We have also received a CE mark for the OraQuick ® In-Home HIV test, although this product is not currently sold in the European Union. The In-Home test is performed in the same manner as the OraQuick ADVANCE ® test, except that it has product labeling and instructions designed for consumers. In addition, we have established toll-free, 24/7, 365-day per year customer telephone support to provide additional information and referral services for consumers that use this product. +OraQuick ® HIV Self-Test +The OraQuick ® HIV Self-Test uses the same diagnostic technology as our U.S. approved OraQuick ADVANCE ® HIV test but is sold for use by individuals in certain foreign countries at a lower cost to meet the needs of those markets. For the past several years, we worked with Population Services International (“PSI”), a leading global health organization, along with UNITAID, the WHO and health officials from several African countries to deploy our Self-Test through the UNITAID-PSI HIV Self-Testing in Africa (“STAR”) project. The OraQuick ® Self-Test has labeling and instructions specifically tailored for each market in which it is sold. The purpose of the STAR project was to generate crucial information about how best to deliver HIV self-testing, how to generate demand for HIV testing in this manner and what the potential public health impact of self-testing will be. Our OraQuick ® Self-Test was chosen by PSI because of its quality, ease-of-use and oral fluid option. The STAR project has largely been completed. This product has received WHO pre-qualification and is eligible for procurement by purchasing entities entitled to access funding and other resources from the Global Fund, UNITAID and other agencies. During 2019, a majority of the sales of our OraQuick ® HIV Self-Test occurred in countries outside of the African countries covered by the STAR project. +3 +OraQuick ® HCV Rapid Antibody Test +Another test available on the OraQuick ® platform is the OraQuick ® HCV rapid antibody test. This product is a qualitative test that can detect antibodies to the hepatitis C virus (“HCV”), in a variety of sample types. The OraQuick ® HCV test operates in substantially the same manner as the OraQuick ADVANCE ® HIV test. +We have received FDA approval and CLIA waiver for use of the test in detecting HCV antibodies in venous whole blood and finger-stick whole blood specimens, making it the first and only rapid HCV test approved by the FDA for use in the United States. The OraQuick ® HCV test has received a CE mark for use with oral fluid, venous whole blood, finger-stick whole blood, plasma and serum and is sold in Europe. This CE-marked product is also registered and sold in other foreign countries and has received WHO pre-qualification. +OraQuick ® Ebola Rapid Antigen Test +In 2019, we received 510(k) clearance from the FDA for our new rapid Ebola test, making it the first and only rapid Ebola test cleared for sale in the U.S. This product utilizes the OraQuick ® technology platform for the detection of Ebola antigen. Under this 510(k) clearance, which came through the FDA’s Breakthrough Devices Program that allows for expedited clearance for treatment or diagnosis of life-threatening or increasingly debilitating diseases, our test can be used with finger-stick and whole blood samples from live patients and oral fluid samples from recently deceased individuals. The uses for this test are limited to individuals that meet certain criteria indicating they may be infected with the Ebola virus, so the test is not available for general screening of individuals that do not meet this criteria. This test had previously received emergency use authorization (“EUA”) from the FDA for emergency use by laboratories and facilities adequately equipped, trained and capable of testing for Ebola infection (including treatment centers and public health clinics). The WHO also previously issued an Emergency Use Assessment and Listing for this product. +OraSure QuickFlu ® Rapid Flu A&B Test +The OraSure QuickFlu ® Rapid Flu A&B test is an FDA 510(k) cleared rapid qualitative test for the detection of influenza (flu) Types A and B, including H1N1 viral infections. The test utilizes specimen collected with a nasal swab, nasopharyngeal swab or nasal aspirate/wash. A reagent is first inserted into a test cartridge, the specimen is added and the test is allowed to flow. Results are available in as little as 10 minutes. This product is manufactured for us under an agreement with a third party and is currently sold in certain U.S. markets. The manufacturer of this product has also obtained a CLIA waiver for use of the test with nasal and nasopharyngeal swabs. +OraSure ® Collection Device +Our OraSure ® oral fluid collection device is used in conjunction with screening and confirmatory tests for HIV-1 antibodies. The generic version of this product can be used for other analytes. This device consists of a small, treated cotton-fiber pad on a handle that is placed in a person’s mouth for two to five minutes. The device collects oral mucosal transudate (“OMT”), a serum-derived fluid that contains higher concentrations of certain antibodies and analytes than saliva. As a result, OMT testing is a highly accurate method for detecting HIV-1 infection and other analytes. +The OraSure ® collection device is FDA approved for use in the detection of HIV-1 antibodies. The generic version is a Class I medical device for the detection of cocaine and cotinine in oral fluid specimens for risk assessment testing. HIV-1 antibody detection using the OraSure ® collection device involves three steps: +• +Collection of an oral fluid specimen using the OraSure ® device; +• +Screening of the specimen for HIV-1 antibodies at a laboratory with an enzyme immunoassay (“EIA”) screening test approved by the FDA for use with the OraSure ® device; and +• +Laboratory confirmation of any positive screening test results with either a western blot confirmatory test or a blood based nucleic acid test. +A trained health care professional then conveys test results and provides appropriate counseling to the individual who was tested. +Tuberculosis (“TB”) Products +OMNIgene ® • SPUTUM is a non-toxic and highly stable reagent that liquefies and decontaminates sputum samples at the point-of-collection or in the lab while preserving the viability of TB bacteria for at least eight (8) days at ambient temperatures. +Although the OMNIgene ® • SPUTUM product is CE marked and was being evaluated by a number of TB laboratories, demand for this product has not met expectations. Accordingly, we decided to stop selling this product in the second half of 2019. +4 +Intercept ® Drug Testing System +A collection device that is substantially similar to the OraSure ® device is sold under the name Intercept ® , and is used to collect oral mucosal transudate or OMT for oral fluid drug testing. We have received FDA 510(k) clearance to use the Intercept ® collection device with laboratory-based EIAs to test for drugs-of-abuse commonly identified by the National Institute for Drug Abuse (“NIDA”) as the NIDA-5 (i.e., tetrahydrocannabinol (“THC” or marijuana), cocaine, opiates, amphetamines/methamphetamines and phencyclidine (“PCP”)), and for barbiturates, methadone and benzodiazepines. Each of these EIAs is also FDA 510(k) cleared for use with the Intercept ® device. Our Intercept ® device and oral fluid assays are sold in the U.S. primarily through laboratory distributors. +We believe that the Intercept ® device has several advantages over competing urine and other drugs-of-abuse testing products, including its lower total testing cost, its non-invasive nature, mobility and accuracy, the ease of maintaining a chain-of-custody, the treatment of test subjects with greater dignity, no requirement for specially-prepared collection facilities and difficulty of sample adulteration. The availability of an oral fluid test is intended to allow our customers to test for drug impairment and eliminate scheduling costs and inconvenience, thereby streamlining the testing process. +We have also developed a next-generation collection device, which we are marketing under the tradename “Intercept i2 ® he ”. This device offers several important advantages over our original Intercept ® device, including a sample adequacy indicator that provides a visual prompt when the appropriate volume of oral fluid has been collected, the ability to collect a larger sample required by current laboratory testing protocols and a more optimized chemistry that results in improved recovery of the targeted drug analytes. The Intercept i2 ® he device is currently being sold as a forensic use only device within the criminal justice and drug treatment markets along with a NIDA-5 panel of fully-automated high-throughput oral fluid drug assays that we distribute under an agreement with Thermo Fisher Scientific (“Thermo Fisher”). Under an amendment to the Thermo Fisher agreement, we have agreed to modify the configuration of our Intercept i2 ® he device and Thermo Fisher will further optimize its assays and related calibrators in order to meet recently issued oral fluid drug testing guidelines issued by the Substance Abuse and Mental Health Services Administration (“SAMHSA”). We also intend to obtain FDA 510(k) clearance of our device for use with a 12-assay panel of the Thermo Fisher assays. +Immunoassay Tests and Reagents +We develop and sell immunoassay tests in formats, known as MICRO-PLATE and AUTO-LYTE ® , to meet the specific needs of our customers. We also sell fully-automated high-throughput oral fluid drug assays developed under our agreement with Thermo Fisher. +In a MICRO-PLATE kit, the sample to be tested is placed into a small plastic receptacle, called a microwell, along with the reagents. The result of the test is determined by the color of the microwell upon completion of the reaction. Controlling the reaction involves the use of reagents by laboratory personnel. Test results are analyzed by any of a variety of commercially available laboratory instruments, which we may also provide to our laboratory customers. MICRO-PLATE tests can be performed on commonly used instruments and can detect drugs in urine, serum and sweat specimens. MICRO-PLATE tests are also used as part of the Intercept ® product line to detect drugs-of-abuse in oral fluid specimens. +AUTO-LYTE ® tests are sold in the form of bottles of liquid reagents. These reagents are run on commercially available laboratory-based automated analytical instruments, which are manufactured by a variety of third parties. AUTO-LYTE ® is typically used in high volume, automated, commercial reference insurance laboratories to detect certain drugs or chemicals in urine. Test results are produced quickly, allowing for high throughput. Our AUTO-LYTE ® tests continue to face strong competition from cheaper “home-brew” tests developed internally by our laboratory customers. As a result, we may eventually stop selling our AUTO-LYTE ® tests. +We previously entered into an agreement with Thermo Fisher under which Thermo Fisher would develop and supply up to 12 fully-automated high-throughput oral fluid drug assays for use with our Intercept i2 ® device. Under this agreement, we are currently selling a NIDA-5 panel of assays supplied by Thermo Fisher in the U.S. forensic market. As noted above, the parties amended this agreement and have agreed to modify our Intercept i2 ® collector and optimize the assays and related calibrators to meet recently issued SAMHSA drug testing guidelines and to pursue FDA 510(k) clearance of the Intercept i2 ® device for use with a 12-assay panel. We believe the offering of an Intercept i2 ® device with a full menu of fully-automated high-throughput oral fluid assays that meet the SAMHSA guidelines will better meet the needs of our laboratory drug testing customers and allow us to compete more effectively against fully automated urine drug assays that dominate the drug testing market. +Q.E.D. ® Saliva Alcohol Test +Our Q.E.D. ® saliva alcohol test is a point-of-care test device that is a cost-effective alternative to breath or blood alcohol testing. The test is a quantitative, saliva-based method for the detection of ethanol, has been cleared for sale by the FDA and has received a CLIA waiver. The U.S. Department of Transportation (“DOT”) has also approved the test. +5 +Each Q.E.D. ® test kit contains a collection stick that is used to collect a sample of saliva and a disposable detection device that displays results in a format similar to a thermometer. The Q.E.D. ® device is easy to operate and instrumentation is not required to read the result. The product has a testing range of 0 to 0.145% blood alcohol and produces results in approximately two minutes. +Molecular Products and Services Segment +Genomic Products +We sell a number of genomic products that provide all-in-one systems for the collection, stabilization, transportation, and storage of DNA and/or RNA from human and animal biologic samples. Our lead products are sold under the Oragene ® and ORAcollect ® brands and are used to collect DNA from human saliva. These products are currently sold to thousands of academic research and commercial customers in many countries worldwide. +Our genomic products are available in several different configurations and contain proprietary chemical solutions that are optimized for the specific application for which each product is designed. Product physical design is focused on ease-of-use and reliability for self or assisted collection of samples. For example, several of the Oragene ® products require users to simply hold the product close to their mouth and spit into the collection device. When the container is closed, the reagents stored in the lid of the container are mixed with the captured saliva and immediately protect the nucleic acids in the sample. This non-invasive collection method yields nucleic acid that remains stable at ambient temperature for extended periods. The stabilizing technology results in high quality and high quantity nucleic acids that are required for most genetic testing and analysis methods. +We believe these products provide significant advantages over competing DNA and RNA collection methods such as blood collection or buccal swabs, particularly in human genetic applications. Benefits include the reliable collection of high-quality and stable genetic samples, use of simple non-invasive collection methods, the ability to store and transport collected samples for extended periods at ambient temperatures and compatibility with fully-automated laboratory testing systems. +We also sell the Colli-Pee ® collection device for the volumetric collection of first void urine samples. This product is used in liquid biopsy applications for the prostate and bladder cancer markets and in the sexually transmitted infection screening market. +Microbiome Products . +We also market several microbiome collection products designed to collect, stabilize and transport the microbial profile from multiple sample types. Unlike genomic DNA, the microbiome of a sample can change over time, especially when exposed to temperature and environment fluctuations. In order to optimize and standardize sample results, a reliable method that captures and preserves (“snapshots”) the microbiome after collection until analysis is required. We believe our products provide such a reliable method. +Our OMNIgene ® • GUT product is an all-in-one system designed to enable an individual to easily self-collect high quality microbial DNA from feces or stool samples for gut microbiome profiling for use in clinical laboratory and research settings. Current methodologies for gut microbiome profiling have distinct shortcomings due to the introduction of bias, leading to a lack of reproducibility in the field. Our product ensures that the fecal sample is fully stabilized immediately upon collection and maintains an accurate and reliable bacterial profile for weeks at room temperature. We have also begun marketing other microbiome collection kits for vaginal and oral samples. +Molecular Services . +Our molecular business also offers customers our GenoFIND TM services, a suite of genomic services that range from package customization and study design optimization to extraction, analysis and reporting services. Our GenoFIND TM offering has become an increasingly valuable tool for meeting the needs of our molecular customers. +Through our subsidiaries, CoreBiome and Diversigen, we also offer our customers microbiome laboratory testing and analytical services. CoreBiome provides its services with a focus on accelerating microbiome discovery for customers in the pharmaceutical, agriculture, and research communities, to unleash the translational potential of the microbiome. Through its proprietary BenchMark TM , BoosterShot TM , and Core Analysis TM platforms, CoreBiome provides fast and information-rich characterizations of microbial diversity and function paired with expert analytics. +Diversigen’s offering provides comprehensive microbiome and metagenomics services focused on solutions to improve human, animal and environmental health. Diversigen has extensive experience with highly diverse microbiome sample types and provides full project life cycle consulting services, including pre-project consulting, study design, extraction and sequencing to complete +6 +bioinformatics analysis. Diversigen is at the forefront for setting quality standards for this industry and was the first company to establish microbiome protocols that comply with CAP accreditation and CLI A guidelines. We are in the process of integrating the services offered through GenoFIND TM , CoreBiome and Diversigen into a unified offering and brand for our customers. +Regulatory Approvals. +Our molecular collection products historically have been sold primarily as Class I medical devices for use by research and academic institutions. We have received FDA 510(k) clearance of the Oragene ® • DX product for use with the eSensor ® Warfarin sensitivity saliva test. A separate 510(k) clearance permits self-collection by consumers when the sample is to be tested with either an exempt or 510(k) cleared molecular test. More recently, we received a generic 510(k) clearance for this product, which we believe will further broaden the use of our Oragene ® • DX device. Our ORAcollect ® product similarly received 510(k) clearance from the FDA. We have also received CE mark approval for the Oragene ® • DNA, ORAcollect ® and OMNIgene ® • GUT collection kits. Both CoreBiome and Diversigen provide molecular services in CLIA-certified laboratories and as noted above, Diversigen’s laboratory protocols comply with CAP guidelines. +Products Under Development +Infectious Disease +Our research and development efforts include programs targeted at expanding and enhancing our infectious disease business. These programs primarily focus on products related to drug monitoring, rapid tests for diseases other than HIV and HCV and drug testing. A significant amount of effort in 2020 will be devoted to modifying our Intercept ® i2he collection device and optimizing the Thermo Fisher fully-automated oral fluid drug assays to meet the recently issued SAMSHA drug testing guidelines. Another development area is focused on increasing the number of country registrations for our HIV Self-Test and expanding our self-testing franchise to include other diseases such as HCV. Finally, we are looking at both internal and external opportunities to develop rapid point-of-care assays for drug adherence testing in the same markets where we currently sell our infectious disease diagnostic products. +Molecular Product and Services +In order to intersect evolving customer needs within the academic and commercial markets, our molecular business product development pipeline is focused on extending offerings across different sample types and analytes within both the genomics and microbiome areas. Genomic customers are demonstrating an increasing demand for RNA collection and stabilization. On the microbiome front, we continue to focus research and development work on collecting and stabilizing microbial DNA, RNA and metabolites from multiple sample types including gut, skin, vagina and saliva. We are also evolving the physical design and features of our products to further enable high throughput processing through improved interoperability with automated platforms. +The field of microbiome services is fast paced with evolving biological understanding and development of new methodologies. Our development efforts are focused on remaining at the forefront of technology, as well as providing new and relevant services to our customers. These development goals are being pursued while we also leverage new sequencing technologies and methodologies to enable scalability for our business. +Research and Development +Research and development expenses were $19.6 million in 2019, $16.3 million in 2018 and $13.4 million in 2017. These expenses include our costs associated with research and development, regulatory affairs, clinical trials and product support. +Sales and Marketing +We attempt to reach our major target markets through a combination of direct sales, strategic arrangements and independent distributors. Our marketing strategy is to create or raise awareness through a full array of marketing activities, which include trade shows, print advertising, special programs, distributor promotions, telemarketing and the use of digital and social media in order to stimulate sales in each target market. +7 +We market our products in the United States and internationally. Consolidated net revenues attributable to customers in the United States were $ 107.3 million, $ 136.8 million and $121.5 million in 2019, 2018 and 2017 , respectively. Consolidated net revenues attributable to international customers amounted to $ 47.3 million, $ 44.9 million and $45.6 million , or 31 %, 25 % and 27% of our total revenues, in 2019, 2018 and 2017 , respectively. For more information about our revenues and long-lived assets attributable to U.S. and international customers, please see Note s 2 and 14 to our consolidated financial statements included elsewhere in this Annual Report. +Infectious Disease Testing - Professional +We market the OraQuick ADVANCE ® HIV-1/2 antibody test directly to customers in the public health market for HIV testing. This market consists of a broad range of clinics and laboratories and includes states, counties, and other governmental agencies, family planning clinics, colleges and universities, correctional facilities and the military. There are also a number of organizations in the public health market, such as AIDS service organizations and various community-based organizations that are set up primarily for the purpose of encouraging and enabling HIV testing. In the past, we sold our OraQuick ADVANCE ® test directly to hospitals in the U.S. through our internal sales force. We are now changing this approach to sell to hospitals primarily through distributors. We also use distributors to sell our OraQuick ADVANCE ® test into the U.S. physician office market and to retail clinics operated by pharmacies. In addition, we distribute our OraQuick ® HIV test in certain foreign countries through distributors. +Our OraQuick ® HCV test is sold primarily to the same markets where our OraQuick ® ADVANCE HIV test is sold, including public health organizations, hospitals, physicians and retail clinics. We also sell this test in other countries through distributors. +We initially sold our OraQuick ® Ebola test under an EUA and our only customer to date has been the CDC, which has purchased the product for field testing in Africa. There were approximately $200,000 of Ebola sales in 2019. Our ability to expand sales of this test to other customers will likely depend on the timing and extent of future outbreaks of the disease and the availability of government or other funding. We recently obtained FDA 510(k) clearance for this product and plan to request pre-qualification with the WHO. +We market the OraSure ® oral fluid collection device for HIV-1 testing, on its own and as a kit in combination with laboratory testing services. To better serve our public health customers, we have contracted a commercial laboratory to provide prepackaged OraSure ® test kits, with prepaid laboratory testing and specimen shipping costs included. +We also have distribution rights to an FDA 510(k) cleared and CLIA waived rapid flu A&B test, which we market under our proprietary OraSure QuickFlu ® tradename. Under our agreement with the supplier of this product, we are permitted to sell this product into the U.S. hospital and public health markets. +Infectious Disease Testing - OTC and Self-Test +We sell our OraQuick ® In-Home test in the U.S. retail or consumer market. Retailers carrying the product include CVS, Walgreens, Rite Aid and Walmart. The product is also available for purchase on-line through certain retailers and our website, www.oraquick.com . The primary target population for our HIV-OTC test comprises young, sexually active adults, with greater purchase intent found in high-risk sub-groups, such as men who have sex with men, African Americans and Latino Americans. +To support individuals that purchase and use our test, we offer toll-free customer support on a 24/7, 365-day per year basis. This service provides consumers with access to trained representatives who can answer questions about HIV/AIDS and the use of our test, and refer consumers to appropriate resources for follow-up confirmatory testing, counseling and medical treatment. +In 2016, we began selling our OraQuick ® HIV Self-Test to PSI (Population Services International) for use in a self-testing pilot program called the HIV Self-Testing in Africa, or STAR, project. Under Phase I of the project, our test was sold in three African countries, Malawi, Zambia and Zimbabwe. We were also selected to participate in Phase II of the project under which additional HIV Self-Tests were deployed. Although our participation in the STAR project has largely been completed, we registered our HIV Self-Test and continue to sell this product in other countries in Africa and elsewhere. +8 +In June 2017, we entered into a C haritable S upport A greement with the Bill & Melinda Gates Foundation (“Gates Foundation”) that has enable d us to offer our OraQuick ® HIV Self-Test at an affordable price in 50 developing countries in Africa and Asia with funding from the Gates Foundation. The funding consist s of support payments tied to the volume of product we sell and reimbursement of certain related costs. The agreement has a four-year term and enable s non-governmental organizations in the eligible countries that receive funding from government or public sector agencies and donors to access our HIV Self - Test at reduced pricing. The funding from the Gates Foundation will be in an aggregate amount not to exceed $20.0 million over the four-year term or $6.0 million each year of the agreement. +In July 2017, our OraQuick ® HIV Self-Test was prequalified by the WHO. WHO prequalification aims to ensure that diagnostic tests for high burden diseases meet global standards of quality, safety, and efficacy in order to optimize use of health resources and improve health outcomes. WHO prequalification enables governmental organizations implementing HIV Self-Test pilots and programs to access international funding to purchase our test. +Substance Abuse Testing +Our substance abuse testing products are marketed to laboratories serving the workplace testing, forensic toxicology, criminal justice and drug rehabilitation markets in the U.S. and certain international markets. +We have entered into agreements for the distribution of our Intercept ® collection device and associated MICRO-PLATE assays for drugs-of-abuse testing in the workplace testing market in the United States and Canada through several laboratory distributors and internationally for workplace, criminal justice and forensic toxicology testing through other distributors. We also market the Intercept ® collection device on its own and as a kit in combination with laboratory testing services. To better serve our workplace customers, we have contracted with commercial laboratories to provide prepackaged Intercept ® test kits, with prepaid laboratory testing and specimen shipping costs included. +The criminal justice market in the United States for our substance abuse testing products consists of a wide variety of entities in the criminal justice system that require drug screening, such as pre-trial services, parole and probation offices, police forces, drug courts, prisons, drug treatment programs and community/family service programs. The forensic toxicology market consists of several hundred laboratories including federal, state and county crime laboratories, medical examiner laboratories and reference laboratories. +As discussed above, we also sell our next generation Intercept i2 ® collection device with a NIDA-5 panel of fully-automated high-throughput oral fluid assays developed with Thermo Fisher for the detection of PCP, THC, opiates, cocaine, methamphetamines and amphetamines. These products are currently sold into the criminal justice and drug treatment markets. Under an amendment to our Thermo Fisher agreement, we plan to obtain FDA 510(k) clearance of our Intercept i2 ® device for use with the NIDA-5 assay panel, along with an additional six fully-automated high-throughput assays in order to expand sales of this product line into the workplace testing market and other markets that require 510(k) cleared drug tests. These products are expected to meet recently issued oral fluid drug testing guidelines issued by SAMHSA, which will enable us to expand sales into markets where employee drug testing is federally regulated. We expect that the 510(k) cleared Intercept i2 ® device and related fully-automated high-throughput assays will eventually replace our original Intercept ® collector and MICRO-PLATE assays in the drug testing market. +We distribute our Q.E.D. ® saliva alcohol test primarily through various distributors in the United States and internationally. The markets for alcohol testing are relatively small and fragmented with a broad range of legal and procedural barriers to entry. Markets range from law enforcement testing to workplace testing of employees in safety sensitive occupations. Typical usage situations include pre-employment, random, post-accident, reasonable-cause and return-to-duty testing. +Insurance Risk Assessment +We currently market the OraSure ® oral fluid collection device for use in screening life insurance applicants in the United States and internationally to test for three of the most important underwriting risk factors: HIV-1, cocaine and cotinine (a metabolite of nicotine). Devices are sold to insurance testing laboratories, which in turn sell the devices to insurance companies, usually in combination with testing services. +We also promote use of the OraSure ® device directly to insurance companies for life insurance risk assessment. Insurance companies then make their own decision regarding which laboratory to use to supply their collection devices and testing services. +There exists a wide range of policy limits where our OraSure ® product is being used. In general, many (but not all) of our insurance company customers use the OraSure ® device in connection with life insurance policies having face amounts of up to $250,000, with some customers using the device for policies of up to $500,000 in amount. Some insurance companies have chosen to extend their +9 +testing to lower policy limits where they did not test at all before, while others have used OraSure ® to replace some of their blood and urine-based testing. In recent years, some insurance customers have adopted a “Simplified Issues” policy, where lab testing is no longer required and instead the applicant completes a questionnaire about personal behaviors. +We also sell our AUTO-LYTE ® assays and reagents in the insurance testing market directly to certain laboratories. +Molecular Products and Services +DNAG sells its products directly to its customers, primarily through its own internal sales force. In many international markets, distributors are used. +Most of DNAG’s revenues are derived from product sales to commercial customers and into the academic and research markets. Sales to commercial customers providing consumer genetics and clinical diagnostic services have been increasing and account for a majority of DNAG’s revenues. A significant portion of DNAG’s sales are derived from repeat customers, in both markets. DNAG also has customers in the livestock and companion animal markets. +DNAG has expanded its market focus by developing new collection devices for the emerging microbiome market, which is focused on the study of microbes and their effect on human health. DNAG’s primary product offering in the microbiome market, OMNIgene ® • GUT, is focused on the human gut microbiome (microbes living in human stool). DNAG is leveraging its existing sales force and global research connections to engage microbiome customers around the world to establish itself as the leader in ease-of-collection, stabilization and transport of this challenging sample type. +During 2019, we began selling the Colli-Pee ® device for the volumetric collection of first void urine, as a result of our acquisition of Novosanis. This product is in its early stages and initial sales are occurring primarily through distributors and collaborations for use in the liquid biopsy and sexually transmitted disease markets. +DNAG is also offering laboratory and analytical services for both genomics and microbiome customers in order to more fully meet the needs of its customers. These services are primarily provided to pharmaceutical and biotech companies and research institutions. During 2019, we substantially expanded our ability to offer microbiome laboratory and bioinformatics services with the acquisition of CoreBiome and Diversigen. We expect to integrate the laboratory operations of CoreBiome and Diversigen so that we can provide a single-integrated offering to our customers. +Significant Products and Customers +Several different products have contributed significantly to our financial performance, accounting for 10% or more of our total revenues during the past three years. The table below shows a breakdown of those product revenues (dollars in thousands). +For the years ended December 31, +2019 +2018 +2017 +Oragene ® +$ +46,701 +$ +69,798 +$ +67,232 +OraQuick ® HIV +43,092 +41,457 +35,148 +OraQuick ® HCV +12,972 +12,394 +25,409 +One of our customers accounted for approximately 15%, 24% and 25% of our net consolidated revenues in 2019, 2018 and 2017, respectively. +Supply and Manufacturing +Our OraQuick ADVANCE ® HIV test, OraQuick ® In-Home HIV test, OraQuick ® HCV test, OraQuick ® Ebola test, OraSure ® , Intercept ® and Intercept i2 ® collection devices, AUTOLYTE and MICRO-PLATE assays and QED ® saliva alcohol test are all manufactured in our Bethlehem, Pennsylvania facilities. We expect to continue to manufacture these products at this location for the foreseeable future. +We have contracted with a third party in Thailand for the assembly of the OraQuick ® HIV device and the OraQuick ® HIV Self-Test in order to supply certain international markets. This supply agreement had an initial term of one year, and automatically renews for additional annual periods unless either party provides a timely notice of termination prior to the end of an annual period. We believe that other firms would be able to assemble these OraQuick ® tests on terms no less favorable than those set forth in the agreement if the Thailand contractor would be unable or unwilling to continue assembling this product. +10 +We can purchase the HIV antigens, the nitrocellulose and certain other critical components , and the HCV and Ebola antigens used in our OraQuick ® product lines only from a limited number of sources. If for any reason these suppliers are unwilling or no longer able to supply our antigen or nitrocellulose needs, we believe that alternative supplies could be obtained at a competitive cost. However, a change in any of the antigens, the nitrocellulose or other critical components used in our products would require FDA approval and some additional development work. This in turn could require significant time to complete, increase our costs and disrupt our ability to manufacture and sell the affected products. +Our MICROPLATE and AUTO-LYTE assays require the production of highly specific and sensitive antibodies corresponding to the antigen of interest. Substantially all our antibody requirements are provided by contract suppliers. We believe that we have adequate reserves of antibody supplies and that we have access to sufficient raw materials for these products. +Our OraSure QuickFlu ® test is manufactured and supplied under a private label agreement with a third party. There is no other supply source for this product. +The fully-automated high-throughput oral fluid drug assays sold with our new Intercept i2 ® collection device are manufactured and supplied under a long-term agreement with Thermo Fisher. There is no other supply source for these products. +DNAG has two long-term contract manufacturing relationships to supply virtually all of its products, including the Oragene ® product line. Many of the raw materials and components used in these products are also purchased from third parties, including one critical component that is purchased from a sole source supplier. We believe there are other suppliers that can manufacture and supply the raw materials and components for the DNAG products. +Our Colli-Pee ® device is currently manufactured at our Belgian assembly facility with components supplied by third party vendors. +Our GenoFIND TM genomics laboratory services are provided to our customers by a third party laboratory. We believe there are other laboratories that can also provide these services. Our microbiome laboratory testing and analytical services are provided by our subsidiaries, CoreBiome and Diversigen. +Employees +As of December 31, 2019, we had 472 full-time employees. Of this total, there were 139 in sales, marketing and client services; 58 in research and development; 187 in operations, manufacturing, quality control, information systems, purchasing and shipping; 44 in quality assurance and regulatory affairs; and 44 in administration and finance. This compares to 398 employees as of December 31, 2018. Our employees are not currently represented by a collective bargaining agreement. +Competition +OSUR Segment +The diagnostic industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger than we are, and have greater financial, research, manufacturing and marketing resources than we do. +The primary competitive factors for our products include price, quality, performance, ease of use, customer service and reputation. Industry competition is based on these and the following additional factors: +• +Scientific and technological capability; +• +Proprietary know-how; +• +The ability to develop and market products and processes; +• +The ability to obtain FDA or other regulatory approvals; +• +The ability to manufacture products that meet applicable FDA or other applicable regulatory requirements; +• +Commercial execution and strength of distribution; +• +Access to adequate capital; +• +The ability to attract and retain qualified personnel; and +• +The availability of patent protection. +11 +A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. +The future market for diagnostic products is expected to be characterized by greater cost consciousness, the development of new technologies, tighter reimbursement policies and consolidation. The purchasers of diagnostic products are expected to place increased emphasis on lowering costs, reducing inventory levels, obtaining better performing products, automation, service and volume discounts. The increased complexity of the market is expected to force many competitors to enter into joint ventures or license certain products or technologies. +We expect competition to intensify as technological advances are made and become more widely known, and as new products reach the market. Furthermore, new testing methodologies could be developed in the future that render our products impractical, uneconomical or obsolete. There can be no assurance that our competitors will not succeed in developing or marketing technologies and products that are more effective than those we develop or that would render our technologies and products obsolete or otherwise commercially unattractive. In addition, there can be no assurance that our competitors will not succeed in obtaining regulatory approval for these products, or introduce or commercialize them, before we can do so. These developments could have a material adverse effect on our business, financial condition and results of operations. +Several companies market or have announced plans to market oral specimen collection devices and tests both within and outside the United States. We expect the number of devices competing with our OraQuick ® , OraSure ® , Intercept ® and Intercept i2 ® devices to increase as the benefits of oral fluid-based testing become more widely accepted. +Competition in the U.S. market for infectious disease testing in medical settings is intense and is expected to increase. Our principal competition for HIV testing in the professional market comes from existing and new point-of-care rapid blood tests, automated laboratory-based blood tests, or other oral fluid-based tests. Our competitors sell both a rapid oral fluid HIV test and a rapid HIV antigen/antibody test that are both FDA approved and CLIA waived. Our OraQuick ® rapid HCV test competes against laboratory-based blood tests in the U.S., as there currently are no other rapid HCV testing products approved by the FDA. +Our competitors in the domestic infectious disease testing market include medical diagnostic companies and specialized biotechnology firms, as well as pharmaceutical companies with biotechnology divisions. Competing tests are often sold at a lower price than we charge for our products. This competition can result in lost sales and degradation of the price (and therefore the applicable profit margins) we can charge for our HIV and HCV tests. +Outside the U.S., our rapid HIV and HCV tests compete against other rapid and laboratory-based tests. Significant sales of these products in Europe have not materialized principally because of differences in European healthcare systems compared to U.S. systems. Unlike in the U.S., adoption of rapid point-of-care diagnostics is not widespread in Europe because laboratory testing is entrenched and healthcare systems are structured around centralized testing models. In addition, many competing tests in international markets are sold at very low prices. We intend to continue to build awareness and develop strategies to expand sales of our OraQuick ® HIV and HCV tests in European and other international markets. +Our OraQuick ® In-Home HIV oral fluid test is the only rapid HIV test approved by the FDA for sale in the U.S. OTC market. We compete against one other non-rapid HIV blood test available in the OTC market, which requires consumers to self-collect a blood sample and then send it to a laboratory for testing. We expect that other non-rapid HIV blood tests will eventually compete with our product. The OraQuick ® HIV Self-Test that we sell in certain international markets is facing competition from other blood-based rapid HIV self-tests. +Competition for our OraQuick ® Ebola test includes government and commercially-developed laboratory and point-of-care molecular tests, along with a small number of rapid antigen tests sold under an FDA EUA. Our Ebola test is the only product with FDA 510(k) clearance for use on both whole blood samples from living patients and oral fluid samples from cadavers. +The OraSure QuickFlu ® test competes primarily against other rapid flu tests sold by various third parties in the U.S. hospital and public health markets. +In the substance abuse testing market, our Intercept ® drug testing system competes with laboratory-based drug testing products using sample matrices such as urine, hair, sweat and oral fluid. We expect competition for our products to intensify, particularly from other domestic and international companies that have developed, or may develop, competing oral fluid drug testing products. +There are at least two competitors that sell fully-automated high-throughput oral fluid drug testing products in unregulated settings in the United States. These competitors sell these assays for use with either their own oral fluid collector or a collector manufactured by another party. These offerings compete against our Intercept ® and Intercept i2 ® collection devices and related oral fluid assays. +12 +Our MICRO-PLATE oral fluid drug assays, which are sold for use with the original Intercept ® collector and our OraSure ® collection device, also continue to come under increasing competitive pressure from “home-brew” assays developed internally by our laboratory customers. Our oral fluid MICRO-PLATE assays also compete with urine-based homogeneous assays that are run on fully-automated, random access analyzers. These tests provide strong competitive pressure because they provide the benefits of automation, including lower costs and short turn-around times. +Our MICRO-PLATE drugs-of-abuse reagents sold in the forensic toxicology market are targeted to forensic testing laboratories where sensitivity, automation and “system solutions” are important. In the past, these laboratories have typically had to rely on radioimmunoassay test methods to provide an adequate level of sensitivity. Radioimmunoassays require radioactive materials, which have a short shelf-life and disposal problems. Our MICRO-PLATE tests meet the laboratories’ sensitivity needs, run on automated equipment, are not radioimmunoassays, and are offered to the laboratory as a complete system solution of reagents, instrumentation and software to meet the specific needs of each customer. We compete with both homogeneous and heterogeneous tests manufactured by many companies. +Sales of our AUTO-LYTE ® urine assays have declined substantially over a number of years, primarily due to competition from “home-brew” assays developed internally by our laboratory customers, which can be produced at a cost lower than the price typically paid for our products. Many of our customers no longer purchase our AUTO-LYTE ® assays, and we may eventually stop selling this product line. +Q.E.D. ® competes against other semi-quantitative saliva-based alcohol tests that have received U.S. Department of Transportation approval as well as breath alcohol tests. Although there are lower priced tests on the market that use oral fluid or breath as a test medium, these tests are qualitative tests that are believed to be substantially lower in quality and provide fewer benefits than our Q.E.D. ® test. +Molecular Products and Services +Our Oragene ® and ORAcollect ® collection systems compete against other types of collection devices used for molecular testing, such as blood collection devices and buccal swabs, which often are sold for prices lower than the prices charged for the Oragene ® and ORAcollect ® products. Although we believe the Oragene ® and ORAcollect ® devices offer a number of advantages over these other products, the availability of lower price competitive devices can result in lost sales and degradation in pricing and profit margin. Our Oragene ® and ORAcollect ® products are also facing increasing competition from similarly designed collection systems which are beginning to enter the market. +OMNIgene ® • GUT is being sold in the emerging microbiome market and competes with a variety of non-standard in-house solutions developed by various researchers, including simply freezing the sample after collection. The microbiome market is expected to require standardization in the methods used for collection and stabilization in order to derive more accurate and repeatable results. To date, DNAG is one of the few vendors to offer a solution that fully meets these requirements. +Our genomic and microbiome laboratory service offerings primarily compete against a number of commercial reference laboratories, specialty laboratories and hospital laboratories in the U.S. +Patents and Proprietary Information +We seek patents and other intellectual property rights to protect and preserve our proprietary technology and our right to capitalize on the results of our research and development activities. We also rely on trade secrets, know-how, continuing technological innovations and licensing opportunities to provide competitive advantages for our products in our markets and to accelerate new product introductions. We regularly search for third-party patents in fields related to our business to shape our own patent and product commercialization strategies as effectively as possible and to identify licensing opportunities. United States patents generally have a maximum term of 20 years from the date an application is filed. +We have four United States patents and numerous foreign patents for the OraSure ® and Intercept ® collection devices and technology relating to oral fluid collection, containers for oral fluids, methods to test oral fluid, formulations for the manufacture of synthetic oral fluid, and methods to control the volume of oral fluid collected and dispersed. The U.S. patents expire from November 2021 to December 2026. We have also applied for additional patents, in both the United States and certain foreign countries, on such products and technology. +We have one United States patent for our OraQuick ® platform expiring in 2028, as well as corresponding related international patents. We also have patent applications pending internationally. +13 +We hold, through our subsidiary, DNAG, twenty United States patents and numerous foreign patents issued for compositions, methods and apparatuses for the collection, stabilization, transportation and storage of nucleic acids (DNA and RNA) from oral fluid and other bodily fluids and tissues. These patents expire from February 2022 through March 2035 . +We hold through our subsidiary, Novosanis, two United States patents and numerous foreign patents covering a medical device for capturing a predetermined volume of first void urine and an intradermal injection device for accurate injection of small volumes of drugs in the skin. These patents expire from April 2034 through April 2035. +Our subsidiary, CoreBiome, has licensed one United States patent and several foreign patent applications from the University of Minnesota for analytical standards to detect and/or measure sampling, processing, and/or amplification errors in a biological samples containing polynucleotide molecules. This license also covers certain software and know-how related to laboratory and bioinformatics procedures and processes. +Our subsidiary, Diversigen, has licensed certain know-how and database assets from the Baylor College of Medicine related to laboratory processes for microbiome and metagenomics services. +We require our employees, consultants, outside collaborators and other advisors to execute confidentiality agreements upon the commencement of employment or consulting relationships with us. These agreements provide that all confidential information developed by or made known to the individual during the course of the individual’s relationship with us is to be kept confidential and not disclosed to third parties except in specific circumstances. In the case of employees and certain consultants, the agreements also provide that all inventions conceived by the individual during his or her tenure with us or the performance by the consultant of services for us will be our exclusive property. +We own rights to trademarks and service marks that we believe are necessary to conduct our business as currently operated. In the United States, we own a number of trademarks, including the OraSure ® , Intercept ® , Intercept i2 ® , OraQuick ® , OraQuick ADVANCE ® , OraSure QuickFlu ® , Q.E.D. ® , Oragene ® , ORAcollect ® , OMNIgene ® , Diversigen ® , Colli-Pee ® , VAX-ID ® , AUTO-LYTE ® , prepIT ® and Hemagene ® trademarks. We also own many of these marks and others in several foreign countries and we are pursuing registration of several other trademarks. +Although important, the issuance of a patent or existence of trademark or trade secret protection does not in itself ensure the success of our business. Competitors may be able to produce products competing with our patented products without infringing our patent rights. Issuance of a patent in one country generally does not prevent manufacture or sale of the patented product in other countries. The issuance of a patent is not conclusive as to validity or as to the enforceable scope of the patent. The validity or enforceability of a patent or trademark can be challenged by litigation after its issuance or registration. If the outcome of such litigation is adverse to the owner of the patent, the owner’s rights could be diminished or withdrawn. Trade secret protection does not prevent independent discovery and exploitation of the secret product or technique. +Government Regulation +General +Most of our products are regulated by the U.S. Food and Drug Administration (“FDA”), along with other federal, state and local agencies and comparable regulatory bodies in other countries. This regulated environment governs almost all aspects of development, production and marketing, including product design and testing, authorizations to market, labeling, advertising and promotion, manufacturing, distribution, post-market surveillance and reporting, and recordkeeping. We believe that our products and procedures are in material compliance with all applicable regulations, but the regulations regarding the manufacture and sale of our products may be unclear and are subject to change. We cannot predict the effect, if any, that these changes might have on our business, financial condition or results of operations. +Many of our FDA-regulated products require some form of review and action by the FDA before they can be marketed in the United States. After approval or clearance by the FDA, we must continue to comply with other FDA requirements applicable to marketed products and are subject to periodic inspections by the FDA and other regulatory bodies. Both before and after approval or clearance, failure to comply with the FDA’s requirements can lead to significant penalties or could disrupt our ability to manufacture and sell these products. In addition, the FDA could refuse permission to obtain certificates needed to export our products if the agency determines that we are not in compliance. +14 +Domestic Regulation +Most of our products are regulated in the United States as in vitro diagnostic and medical devices. +There are several mechanisms by which regulated devices can be placed on the market in the United States. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act. To obtain this clearance from the FDA, the manufacturer must submit to the FDA a premarket notification that it intends to begin marketing the product, and show that the product is substantially equivalent to another legally marketed predicate device (i.e., a device that has been cleared through the 510(k) process; a device that was legally marketed prior to May 28, 1976; a device that has been downclassified by the FDA; or a device that FDA has previously determined to be exempt from the 510(k) process). To be substantially equivalent, an applicant must show that when compared to a predicate, the new device has the same intended use and same technology, or if different technology, that the new device is as safe and effective as the predicate and does not raise different questions of safety and effectiveness. In all cases, data from some form of performance testing is required and in some cases, the submission must include data from human clinical studies. An applicant must submit a 510(k) application at least 90 days before commercial distribution of the affected product commences. Marketing may only commence when the FDA issues a clearance letter finding that the new device is substantially equivalent to the predicate device. The standards and data requirements necessary for the clearance of a new device may be unclear or may be subject to change. Although FDA clearance usually takes from four to twelve months, in some cases more than a year may be required before clearance is obtained, if at all. +If the device does not qualify for the 510(k) procedure, either because there is no existing predicate device, it is not substantially equivalent to a legally marketed predicate device or because it is classified by the FDA as a high risk device, the FDA must approve either a request for de novo classification or a premarket approval application, or PMA, before marketing can begin. A de novo classification is an alternate pathway to classify novel devices of low to moderate risk for which no substantially equivalent predicate device exists. Clearance of a de novo request generally takes 150 days from the time of submission of the de novo request, although it can take longer. PMAs are generally required for devices that are determined to be high risk and must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness for the intended use(s) of the device. A PMA is typically a complex submission, supported by valid scientific evidence, including the results of preclinical and clinical studies, usability data, detailed information about the manufacturing process for the device, and other data and information. Preparing a PMA is a resource-intensive and time-consuming process. Once a PMA has been submitted, the FDA is required to review the submission within 180 days. However, the FDA’s review may be, and often is, much longer, in many cases requiring one to three years or more, and may include requests for additional data, review by an independent panel of experts, and facility inspections before approval is granted, if at all. +If the FDA approves the PMA, it may place restrictions on the device. If the FDA’s evaluation of the PMA or the manufacturing facility is not favorable, the FDA may deny approval of the PMA application or issue a “not approvable” letter. The FDA may also require additional clinical trials, which can delay the PMA approval process by several years or prevent a PMA approval from being obtained. +If the FDA discovers that an applicant has submitted false or misleading information in any application or notification, the FDA may take action against the applicant and its employees or refuse to review submissions until certain requirements are met pursuant to its Application Integrity Policy (AIP). Delays in receipt of or failure to receive such clearances or approvals, the loss of previously received clearances or approvals, or the failure to comply with existing or future regulatory requirements could have a material adverse effect on our business, financial condition and results of operations. +If there are any modifications made to our marketed devices, a new premarket notification or PMA supplement may be required to be submitted to, and approved by, the FDA, before the modified device may be marketed. A new PMA or a PMA supplement is required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s intended use(s), manufacturing process, manufacturing facility, critical components, labeling and design. Likewise, a new 510(k) clearance is required for any modification that could significantly affect the safety or effectiveness of the device, e.g. a significant change or modification in design, material, chemical composition, energy source, or manufacturing process or a major change or modification in the intended use(s) of the device. +A clinical trial may be required in support of a 510(k) submission and generally is required for a de novo or PMA application. These trials generally require an Investigational Device Exemption, or IDE, application approved in advance by the FDA for a specified number of patients, unless the proposed study is deemed to be exempt from the IDE requirements. In addition, if a study meets the requirements for a non-significant risk study, it may be eligible for compliance with “abbreviated” IDE requirements, which include a subset of the requirements applicable to significant risk medical device studies. If a full IDE is required, an IDE application must be supported by appropriate data, such as laboratory testing results, protocols for the proposed investigation, and other information demonstrating that the device is appropriate for use with humans in a clinical study. Clinical trials may begin if the IDE application is +15 +approved by the FDA and the appropriate institutional review boards, or IRBs, at the clinical trial sites. Submission of an IDE application does not give assurance that the FDA will issue the IDE. If the IDE application is approved, there can be no assurance the FDA will determine that the data derived from the trial(s) support the ultimate approval or clearance of the device or warrant the continuation of clinical trials. An IDE supplement must be submitted to and approved by the FDA before a sponsor or investigator may make a change to the investigational plan in such a way that may affect its scientific soundness, study indication or the rights, safety or welfare of human subjects. The trial must also comply with the FDA’s regulations, including the requirement that informed consent be obtained from each subject, and with clinical trial reporting regulations that require submission of information on certain clinical trials to a database maintained by the National Institutes of Health. Even if a trial is completed, the results of clinical testing may not adequately demonstrate the safety and efficacy of the device or may otherwise not be sufficient to obtain FDA clearance to market the product in the United States. +Some of our products are used for research only or other nonclinical or non-diagnostic purposes. Our molecular collection products are sold to many academic and research institutions for research purposes and our drugs-of-abuse products are sold to laboratories and clinics for forensic or other non-medical uses. The FDA does not currently regulate products used for these purposes, although other state and federal regulatory requirements may apply. +Another option for marketing a product in the U.S. is through an EUA that is granted by the FDA as a result of the Secretary of Health and Human Services declaring an emergency justifying the authorization of emergency use of certain in vitro diagnostic devices to aid in addressing the emergency. Typically, analytical and clinical studies are completed as required by the FDA. Products are exempt from design controls and other quality requirements in order to expedite development of diagnostic tools to aid in the diagnosis of viral pathogens that have the potential to affect public health. +Most devices distributed in the United States must comply with the FDA’s Quality System Regulations (“QSRs”), including current good manufacturing practices. These regulations govern the entire lifecycle of a medical device, including design, manufacture, testing, release, packaging, distribution, documentation and purchasing as well as complaint handling, corrective and preventative actions, and internal auditing. In complying with the QSRs, manufacturers must continue to expend time, money and effort in the area of production, quality, and postmarket surveillance to ensure full compliance. +Companies are also subject to other post-market and general requirements, including product listing and establishment regulations, which help facilitate FDA inspections and other regulatory action, post-market surveillance requests, restrictions imposed on marketed products, promotional standards and requirements for recordkeeping and reporting of certain adverse reactions and malfunctions. Device reporting regulations require that manufacturers report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur. +The FDA regularly inspects companies to determine compliance with the QSRs and other post-market requirements. Failure to comply with statutory requirements and the FDA’s regulations can result in an FDA Form 483 (which is issued by the FDA at the conclusion of an inspection when an investigator has observed any conditions that may constitute violations), public warning letters, monetary penalties against a company or its officers and employees, suspension or withdrawal of regulatory approvals, operating restrictions, total or partial suspension of production, injunctions, product recalls, product detentions, refusal to provide export certificates, seizure of products and criminal prosecution. We believe that our facilities and procedures are in material compliance with the FDA’s OSR regulations and other postmarket requirements, but the regulations are subject to change or may be unclear, and we cannot be sure that FDA investigators will agree with our compliance with the FDA’s postmarket requirements. +The Clinical Laboratory Improvement Amendments of 1988, or CLIA, prohibit any facility that conducts laboratory testing on specimens derived from humans from providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings, unless there is in effect for such facility a certificate issued by the U.S. Department of Health and Human Services applicable to the category of examination or procedure performed. Tests may be waived from this regulatory oversight if they meet certain requirements established under CLIA. We consider the applicability of CLIA requirements in the design and development of our products. We have obtained a waiver of the CLIA requirements for our OraQuick ADVANCE ® rapid HIV-1/2 antibody test, our OraQuick ® HCV rapid antibody test and our Q.E.D. ® alcohol saliva test and may seek similar waivers for certain other products. In addition, the supplier of the OraSure Quick-Flu ® test has obtained a CLIA waiver for that product. A CLIA waiver allows certain customers to use the waived products that may not have been able to use them without complying with applicable quality control and other requirements. +The laboratory services provided by our subsidiaries, CoreBiome and Diversigen, operate under the Clinical Laboratory Improvement Amendments of 1988, or CLIA, and consist of microbiome and metagenomics sequencing, bioinformatics and analysis. CoreBiome has recently received a CLIA certificate of registration in Minnesota and Diversigen operates under the Baylor College of Medicine CLIA certificate of compliance and CAP accreditation. A CLIA certificate of compliance is issued once a state regulator or the Center +16 +for Medicare and Medicaid Services determines that the laboratory is compliant with the applicable CLIA requirements. CAP accredits laboratories performing testing on specimens from human beings or animals, using methodologies and clinical applications within the expertise of the laboratory accreditation program. +Certain of our products may also be affected by state regulations in the United States, which can restrict the use and sale of certain diagnostic products. We are presently working with legislators or regulators in certain of these states in an effort to modify or remove any restrictions affecting our ability to sell products. +Advertising and Promotion +Advertising and promotion of medical devices, in addition to being regulated by the FDA, are also regulated by the Federal Trade Commission (“FTC”) and by other federal and state regulatory and enforcement authorities, including the Department of Justice (“DOJ”), the Office of Inspector General of the Department of Health and Human Services, and various state attorneys general. Although physicians are permitted to exercise medical judgment to use medical devices for indications other than those cleared or approved by the FDA, we may not promote our products for such “off-label” uses and can only market our products for cleared or approved uses. Promotional activities for FDA-regulated products of other companies have also been the subject of enforcement actions brought under healthcare reimbursement laws and consumer protection statutes. In addition, under the federal Lanham Act and similar state laws, competitors and others can initiate litigation relating to advertising claims. If the FDA determines that our promotional materials or training constitute promotion of an uncleared or unapproved use, it could request that we modify our training or promotional materials or subject us to regulatory or enforcement actions, including the issuance of an untitled letter, a notice of violation, a warning letter, injunction, seizure, civil fine or criminal penalties. FTC enforcement actions often result in consent decrees that constrain future actions. DOJ prosecutions can result in significant criminal and civil penalties, including exclusion from the Medicare and Medicaid programs. If an enforcement action is brought by the FDA or FTC, our reputation could be damaged and sales of our products could be impaired. +Import and Export Requirements +Products for export from the United States are subject to foreign countries’ import requirements and the exporting requirements of the FDA, as applicable. In particular, international sales of medical devices manufactured in the United States that are not approved or cleared by the FDA for use in the United States, or are banned or deviate from lawful performance standards, are subject to FDA export requirements. +Foreign countries often require, among other things, an FDA certificate for products for export, also called a Certificate for Foreign Government (“CFG”). To obtain this certificate from the FDA, the device manufacturer must apply to the FDA. The FDA certifies that the product has been granted clearance or approval in the United States and that the manufacturing facilities were in compliance with QSR regulations at the time of the last FDA inspection. If the FDA determines that our facilities or procedures do not comply with the QSR regulations, it may refuse to provide such certificates until we resolve the issues to the FDA’s satisfaction. Failure to obtain a CFG could inhibit our ability to export our products to countries that require such certificates. +International +We are also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval (or pre-qualification or endorsement) from international public health agencies, such as the World Health Organization, in order to sell products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for U.S. governmental approvals. We generally pursue approval only in those countries that we believe have a significant market opportunity. +The International Organization for Standardization (“ISO”) is a worldwide federation of national standards bodies from some 130 countries, established in 1947. The mission of the ISO is to promote the development of standardization and related activities in the world with a view to facilitating the international exchange of goods and services. ISO certification indicates that our quality system complies with standards applicable to activities ranging from initial product design and development through production and distribution. +In the European Union (“EU”), products that fall under the scope of the Medical Devices Directive (“MDD”) and the In Vitro Diagnostic Directive (“IVDD”) are not subject to the prior approval of a regulatory authority, but, depending on the class of product, may require prior review by a notified body. Notified bodies are accredited and supervised by national regulatory authorities to conduct conformity assessment procedures of medical devices or other products. Such products must comply with certain essential requirements listed in those directives. ISO certification creates a rebuttable presumption that the product satisfies the applicable +17 +requirements. Compliance with these requirements allows us to complete the applicable conformity assessment procedure, involving a notified body where necessary, and to affix the CE mark to our products, without which they may not be placed on the market in the EU. +In addition, the EU has adopted the EU Medical device Regulation (the “EU MDR”) and the In Vitro Diagnostic Regulation (the “EU IVDR”), each of which impose stricter requirements for the marketing and sale of medical devices, including in the area of clinical evaluation requirements, quality systems and post-market surveillance. Manufacturers of currently approved medical devices will have until May 2020 to meet the requirements of the EU MDR and until May 2022 to meet the EU IVDR. Compliance with these regulations may be expensive and time-consuming. Failure to meet these requirements could adversely impact our business in the EU and other regions that tie their product registrations to the EU requirements. +We have completed the applicable conformity assessment procedures and obtained the right to use the CE mark for the OraQuick ADVANCE ® HIV-1/2 test, OraQuick In-Home HIV Test, the OraQuick ® HCV test and certain of the Oragene ® collection kits and OMNIgene ® products sold by DNAG and the Colli-Pee ® first-void urine collection devices manufactured and sold by Novosanis. +We must also comply with certain registration and licensing requirements as dictated by Health Canada, prior to commencing sales in Canada. We have completed this process for several of our current products and may do so with respect to other products in the future. In addition, Canadian law requires manufacturers of medical devices to have a quality management system that meets various ISO requirements in order to obtain a license to sell their devices in Canada. Health Canada also requires all companies that market Class II, Class III and Class IV products in Canada to be certified as part of the Medical Device Single Audit Program (MDSAP). We received this certification for our OSUR segment in June 2019. +We have obtained WHO pre-qualification for our OraQuick ® HIV Self-Test and OraQuick ® HCV test and we will likely seek WHO pre-qualification or endorsement for certain other products sold into international markets. +Anti-Kickback and Other Fraud and Abuse Laws +The Federal Anti-Kickback Statute prohibits the knowing and willful offer, payment, solicitation, or receipt of any form of remuneration in return for, or to induce: +• +The referral of an individual to a person for the furnishing or arranging for the furnishing of items or services reimbursable under Medicare, Medicaid or other governmental healthcare programs; or +• +The purchase, lease, or order of, or the arrangement or recommendation of the purchasing, leasing, or ordering of any item or service reimbursable under Medicare, Medicaid, or other governmental healthcare programs. +Our products are or may be purchased by customers that will seek or receive reimbursement under Medicare, Medicaid or other governmental healthcare programs. Noncompliance with the federal anti-kickback statute can result in exclusion from Medicare, Medicaid or other governmental healthcare programs, and/or restrictions on our ability to operate in certain jurisdictions, as well as civil and criminal penalties, any of which could have an adverse effect on our business and results of operations. +The Federal Civil Monetary Penalties Law prohibits the offering or transferring of remuneration to a Medicare or Medicaid beneficiary that the person knows or should know is likely to influence the beneficiary’s selection of a particular provider, practitioner or supplier of Medicare or Medicaid payable items or services. Noncompliance can result in civil monetary penalties for each wrongful act, assessment of three times the amount claimed for each item or service and exclusion from the Federal healthcare programs. +Many states have also adopted some form of anti-kickback laws. A determination of liability under such laws could result in fines and penalties, restrictions on our ability to operate in these jurisdictions and significant damage to our reputation. +We are also subject to other federal and state laws targeting fraud and abuse in the healthcare industry, including false claims laws, marketing conduct laws and laws constraining the sales, marketing and other promotional activities of manufacturers of medical devices by limiting the kinds of financial arrangements, including sales programs, such manufacturers can enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. Violations of these laws may be punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government healthcare programs such as Medicare and Medicaid. These laws and regulations are wide ranging and subject to changing interpretation and application. In recent years, there has been greater scrutiny of marketing practices in the medical device industry which has resulted in several government investigations by various government authorities and the introduction and/or passage of federal and state legislation regulating interactions between medical device manufacturers and healthcare professionals and providers and requiring the disclosure by medical +18 +device manufacturers of payments to certain healthcare professionals and providers. For example, under the Sunshine Act provisions of the Affordable Care Act, device manufacturers are subject to new federal reporting and disclosure requirements with regard to payments or other transfers of value made to physicians and teaching hospitals. Reports submitted under the Sunshine Act are placed in a public database. Device manufacturers are required to submit annual reports by March 31 which cover the prior calendar year. To be in compliance with such disclosure laws, we have implemented necessary systems to accurately track gifts and other payments. +We have implemented a written Policy on Interactions with Health Care Professionals, which is based on the Code of Conduct for Interactions with Health Care Professionals promulgated by the Advanced Medical Technology Association, or AdvaMed, a leading trade association representing medical device manufacturers. The Policy applies to all employees and is intended to comply with applicable state and federal laws, regulations and government guidance. The Policy addresses interactions related to sales and marketing practices, research and development, product training and education, grants and charitable contributions, support of third-party educational conferences, and consulting arrangements. While we believe that our practices are in compliance with the Anti-Kickback and other fraud and abuse laws, the standards for compliance with such statutes can be unclear and subject to change. +Foreign Corrupt Practices Act and Other Anti-Corruption Laws +The U.S. Foreign Corrupt Practices Act (“FCPA”) prohibits corporations and individuals from engaging in certain activities to obtain or retain business or to influence a person working in an official capacity. It is illegal to use any means of interstate commerce corruptly in the furtherance of any offer, payment, promise to pay or authorization of payment of anything of value to any foreign government official, government staff member, political party or political candidate in an attempt to obtain or retain business or to otherwise influence a person working in an official capacity. Our present and future business has and will continue to be subject to the FCPA and various other laws, rules and/or regulations applicable to us as a result of our international sales. Those laws include the U.K. Bribery Act (the “Bribery Act”), which proscribes giving and receiving bribes in the public and private sectors, bribing a foreign public official, and failing to have adequate procedures to prevent employees and other agents from giving bribes. U.S. companies that conduct business in the United Kingdom generally will be subject to the Bribery Act. Penalties under the Bribery Act include potentially unlimited fines for companies and criminal sanctions for corporate officers under certain circumstances. +Environmental Regulation +Because of the nature of our current and proposed research, development, and manufacturing processes, we are subject to stringent federal, state and local laws, rules, regulations and policies governing the use, generation, manufacture, storage, air emission, effluent discharge and handling and disposal of solid wastes, hazardous materials and hazardous wastes. Products that we sell in Europe are subject to regulation in European Union, or EU, markets under the Restriction of the Use of Hazardous Substances Directive, or RoHS. RoHS prohibits companies from selling products which contain certain hazardous materials, including lead, mercury, cadmium, chromium, polybrominated biphenyls and polybrominated diphenyl ethers, in EU member states. In addition, the EU’s Registration, Evaluation, Authorization, and Restriction of Chemicals Directive also restricts substances of very high concern in products. +Future environmental laws may require us to alter our manufacturing processes, thereby increasing our manufacturing costs. We believe that our products and manufacturing processes at our facilities comply in all material respects with applicable environmental laws and worker health and safety laws; however, the risk of environmental liabilities cannot be completely eliminated. +The foregoing discussion of our business should be read in conjunction with the consolidated financial statements and accompanying notes included in Item 15 of this Annual Report. +19 +ITEM 1A. +Risk Factors +You should carefully consider the risks and uncertainties described below, together with all of the other information included in this Annual Report and our other SEC filings, in considering our business and prospects. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not disclosed or not presently known to us or that we currently deem immaterial also may impair our business operations. The occurrence of any of the following risks could harm our business, financial condition or results of operations. +Risks Relating to Products, Marketing and Sales +Customer Concentration and Purchase Seasonality Creates Risk for Our Business. +Our revenues have been heavily impacted by purchases from a few large customers. For example, our molecular collections product sales grew from $75.1 million in 2017 to $86.5 million in 2018, largely as a result of increased orders of our Oragene ® collection systems by our largest customer serving the consumer genomics market. However, sales of molecular products declined in 2019 to $70.8 million. In November 2017, we announced the execution of a multi-year purchase agreement for the sale of $144 million of our Oragene ® product to a large consumer genomics customer. The reduction in molecular product sales in 2019 was largely due to the large consumer genetics customer, which changed its promotional and purchasing plans at the end of 2018 and lowered purchases in 2019. We recently amended our agreement with this customer to extend its term for an additional two years and lower the customer’s annual purchase volumes to better reflect market conditions, although the aggregate purchase commitment under this agreement did not change. +We expect that sales to the large consumer genetics customer will continue to be a significant contributor to our molecular business. As a result, certain parts of our business may continue to have a high customer concentration and depend disproportionately on a few large customers. In addition, demand from the large consumer genomics customer increased significantly in prior periods due to special retail promotions and holiday shopping towards the end of these years. To the extent that such a large customer fails to meet its purchase commitments, does not continue such promotional programs, changes its ordering patterns or business strategy, or otherwise reduces its purchases or stops purchasing our products, or if we experience difficulty in meeting the high demand by these larger customers for our products, our revenues and results of operations could be adversely affected. +Changes in the Genomics Market May Adversely Affect our Business . +The genomics market has been the largest component of our overall molecular business segment for some time and the major driver of this market has been ancestry testing which offers products and services to consumers to provide them with genealogical information. The ancestry market is maturing and sales to this market have declined in recent periods. As noted above, our genomics revenues have been reduced, primarily due to a change in promotional strategies and purchasing patterns by our largest customer which serves the consumer ancestry and genetic testing market. This trend in the ancestry testing market is continuing and is expected to adversely affect our revenues and results of operations in future periods. +In an effort to increase our molecular revenues, we have devoted increasing time and attention to expanding sales of our genomics products internationally, including in the Asia-Pacific and other markets. While we believe these new markets represent large growth opportunities, there is no assurance that we will be successful in capitalizing on these opportunities or that we will be able to increase our international product sales consistent with our expectations. Factors that include, but are not limited to, the market acceptance of our products, available funding, cost containment strategies implemented by customers, increasing competition and regulatory constraints could limit sales of our genomics products into these international markets. To the extent that we are unsuccessful or limited in expanding our business in the Asia-Pacific or other new markets, our revenues and results of operations could be negatively affected. +Despite the challenges that we face in the ancestry market, we believe there is significant growth opportunity for our genomics products in the area of disease risk management (“DRM”). However, during 2019, the U.S. Department of Justice (“DOJ”) investigated several telemedicine companies and individuals for allegedly submitting fraudulent insurance claims to Medicare for cancer genetic screening and pharmacogenomics testing. Several of our customers were included in the DOJ investigation. These activities have had a negative impact on our revenues and to the extent such allegedly fraudulent insurance billing practices continue, our future genomic revenues could be adversely affected. +20 +Our Future Success Depends Upon Market Acceptance of Our Existing and Future Products and Service Offerings . +We believe successful new product and service introductions provide a significant competitive advantage because customers make an investment of time in selecting and learning to use a new product or service and are reluctant to switch thereafter. Our future success will depend, in part, on the market acceptance, and the timing of such acceptance, of new products such as our OraQuick ® HIV Self-Test , OraQuick ® Ebola test and OMNIgene ® • GUT product offerings, and other new products or technologies that may be developed or acquired. In addition, our future revenues will depend on market acceptance of new service offerings, such as the microbiome laboratory testing and analytical services we provide through CoreBioime and Diversigen. To achieve market acceptance, we will likely be required to undertake substantial marketing efforts and spend significant funds to inform potential customers and the public of the existence and perceived benefits of these products and services. In addition, governmental funding for the purchase of our products and services may be needed to help create market acceptance and expand the use of our products. +There may be limited evidence on which to evaluate the market reaction to products and services that may be developed and our marketing efforts for new products and services may not be successful. The market for microbiome products and services is in its early stages and its future development and acceptance by our customers is uncertain. It is also possible that governmental funding may be limited for new products, such as our OraQuick ® Ebola test or the new sample collection and stabilization products being commercialized by DNAG. As such, there can be no assurance that any products or services will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. +If Acceptance and Adoption of Oral Fluid Testing and Collection Products Does Not Continue, Our Future Results May Suffer. +We have made significant progress in gaining acceptance of oral fluid testing products, particularly for (i) HIV testing in the public health, hospital, insurance and other markets, and (ii) drugs-of-abuse testing in the workplace and criminal justice markets. Our subsidiary, DNAG, has also made significant progress in gaining acceptance of oral fluid collection products that are used with molecular testing applications. However, the degree of acceptance for these products is uncertain, and one or more markets may resist the adoption of oral fluid products as a replacement for other testing or collection methods in use today. As a result, there can be no assurance that we will be able to expand the use of our oral fluid testing products in these or other markets. +Our Customers May Resist Adoption of Rapid Point-of-Care Diagnostic Testing. +Sales of our rapid point-of-care diagnostic products, such as our OraQuick ADVANCE ® HIV-1/2, OraQuick ® HCV, OraQuick ® In-Home HIV test and OraQuick ® HIV Self-Test products, are an important part of our business. Rapid point-of-care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by consumers at home without sending samples to central laboratories and can help ensure that test results are delivered to the individuals being tested. +However, clinical reference laboratories and hospital-based laboratories currently provide the majority of diagnostic tests used by physicians and other healthcare providers in the U.S. In certain international markets such as Europe, diagnostic testing is performed primarily by centralized laboratories. Our future sales will depend, in part, on our ability to expand market acceptance of rapid point-of-care testing by physicians, other healthcare providers and consumers and successfully compete against laboratory testing methods and products. We expect that clinical reference and other hospital-based laboratories will continue to compete vigorously against our rapid point-of-care products. Even if we can demonstrate that our products are more cost effective, save time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid point-of-care tests and instead may choose to obtain diagnostic results through laboratory tests. Our failure to achieve and expand market acceptance of our rapid point-of-care diagnostic tests with customers would have a negative effect on our future sales growth. +We Expect to Face Increasing Competition From Other Providers of Diagnostic Tests, Sample Collection Products and Molecular Laboratory Services. +Our rapid point-of-care tests compete with similar point-of-care products made by our competitors. This competition is particularly evident with respect to our OraQuick ADVANCE ® HIV-1/2 test and our HIV Self-Test. The Oragene ® product line sold by our subsidiary, DNAG, competes against other molecular collection products, such as blood collection kits and buccal swabs and will likely face additional competition from collection devices similar in design and operation to our Oragene ® and ORACollect ® products. +Our genetic and microbiome laboratory services business is expected to face increasing competition, primarily from large commercial reference laboratories, hospital-based laboratories and specialty laboratories. We believe there is significant opportunity in the markets for these services, particularly the microbiome market which is still in the early stages. As these markets evolve and expand, we expect competition for genomic and microbiome laboratory services to intensify. +21 +A number of our competitors are making investments in competing technologies , products and services , and several may have a competitive advantage because of their greater financial, technical, research and other resources. Some competitors offer broader product lines and service offerings , aggressively discount prices for their products and services and may have greater name recognition than we have. We also face competition from certain of our distributors or former customers that have created , or may decide to create, their own products to compete with ours. If our competitors take market share from our offerings through more effective marketing or competitive pricing, higher quality or technological superiority, our revenues, margins and operating results could be adversely affected. In addition, our revenues and operating results could be negatively impacted if some of our customers use internally develop ed or acquire d sample collection devices or services in order to reduce costs. +Our Inability to Carry Out Certain of Our Marketing and Sales Plans May Make it Difficult for Us to Grow or Maintain Our Business. +We have implemented in the past, and we intend to implement in the future, an aggressive sales and marketing plan to expand sales of our products and services. If we are unable to successfully implement these programs or modify these programs in response to evolving market and economic conditions, we may be unable to grow and our business could suffer. +Our Product Sales Cycles Can be Lengthy, and May Depend on Public Funding, Which Can Cause Variability and Unpredictability in Our Operating Results. +The sales cycles for certain of our products can be lengthy and unpredictable, which makes it more difficult to accurately forecast revenues in a given period and may cause revenues and operating results to vary from period to period. Sales of our products often involve purchasing decisions by large public and private institutions, may require many levels of approval and may be dependent on economic or political conditions and the availability of grants or funding from governmental or public health agencies which can vary from period to period in both amount and timing. For example, in past years our OraQuick ADVANCE ® HIV-1/2 test has been purchased through bulk procurement or other funding provided by governmental agencies. Our OraQuick ® HCV test has been purchased by customers who receive government funding, and we believe increased funding from the CDC and other agencies will be required to substantially increase the volume of HCV testing, especially in the public health market. We also sold large quantities of our OraQuick ® HCV test to foreign governments and agencies for use in broad-based or country-wide HCV elimination programs. There can be no assurance that purchases or funding from these agencies will occur or continue. As a result, we may expend considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with our objectives. +We May Face Product Liability Claims for Injuries Resulting From the Use of Our Products. +We may be held liable if any of our products, or any product which is made with the use or incorporation of any of our technologies, causes injury of any type or is found otherwise unsuitable during product testing, manufacturing, marketing, sale or usage. There is no assurance that we would be successful in defending any product liability lawsuits brought against us. Moreover, there is no assurance that our products will not be included in unethical, illegal or inappropriate research or applications, which may in turn put us at risk of litigation. Regardless of merit or eventual outcome, product liability claims could result in: +• +Decreased demand for our products; +• +Lost revenues; +• +Damage to our image or reputation; +• +Costs related to litigation; +• +Increased product liability insurance costs; +• +Diversion of management time and attention; and +• +Incurrence of damages payable to plaintiffs. +We are selling the OraQuick ® In-Home HIV test in the United States OTC market, and we offer HIV Self-Tests to consumers internationally. We believe the sale of products for use by consumers increases our potential exposure to product liability and other claims. +22 +The Insurance We Purchase to Cover Our Potential Business Risks May be Inadequate. +Although we believe that our present product liability and other insurance coverage is sufficient to cover our current estimated exposures, we cannot be sure that we will not incur liabilities in excess of our policy limits. In addition, although we believe that we will be able to continue to obtain adequate coverage in the future, there is no assurance that we will be able to do so at acceptable costs. +We Could Suffer Monetary Damages, Incur Substantial Costs or be Prevented From Using Technologies Important to Our Products and Services as a Result of Legal Proceedings. +We have been, and in the future may become, involved in various legal proceedings arising out of our businesses. These may include commercial disputes, negligence claims or various other lawsuits arising in the ordinary course of our business, including employment matters. Such lawsuits can seek damages, sometimes in substantial amounts, for commercial or personal injuries allegedly suffered and can include claims for punitive or other special damages. An adverse ruling or rulings in one or more such lawsuits could, individually or in the aggregate, result in the termination or modification of a material contract or otherwise have a material adverse effect on our sales, operations or financial performance. +Performance of Our Products May Affect Our Revenues, Stock Price and Reputation. +Our products are generally sold with labeling that contains performance claims approved or cleared by the FDA or other regulators. However, our products may not perform as expected. For example, a defect in one of our diagnostic or specimen collection products or a failure by a customer to follow proper testing procedures, may cause the product to report inaccurate information such as a false positive result or a false negative result. A false positive or negative result can also occur even when there is no apparent product defect and the customer has apparently used our product properly. Identifying the root cause of a product performance or quality issue can be difficult and time consuming. +If our products fail to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers, customers may switch to a competing product or otherwise stop using our products, and our revenues could be adversely affected. Under such circumstances, we may be required to implement shipment holds or product recalls and incur warranty obligations, which would increase our costs. In addition, poor performance by one or more of our products and publicity surrounding such performance could have an adverse effect on our reputation, our continuing ability to sell products and the prevailing market price of our Common Stock. +Our Inability To Expand International Sales Could Adversely Affect Our Business and Results of Operations. +One of our strategic priorities is to substantially expand our product sales internationally. An opportunity to accomplish this objective is with the sale of our OraQuick ® HIV Self-Test in support of large self-testing programs in certain African countries and elsewhere. We are also working to expand international sales of our professional HIV and HCV products and our molecular collection kits. While we believe international sales these and other products represent attractive long-term opportunities with significant growth potential, there is no guarantee that these opportunities will continue or increase. Among other factors, competition from other cheaper products and the uncertainties of available funding could negatively impact the success of these opportunities. If international sales of these products do not occur or increase or if we are otherwise unable to expand international sales of our products, our revenues and results of operations could be negatively impacted. +In addition, market conditions in many countries often require that we sell our products at a price below our typical U.S. or European pricing in order to participate in these markets. As a result, sales in certain countries may contribute lower profit margins to our business. To the extent these international sales comprise a large or increasing part of our business, our gross margins will be negatively affected. In addition, we may have difficulty selling our products at a sufficiently low price to maintain or increase this business over the long term without funding support from public health entities, government agencies or other sources. If we are unable to obtain or continue this funding support at sufficient levels, or at all, our revenues and results of operations could be negatively affected. +Our International Presence May Increase Our Risks and Expose Our Business to Regulatory, Cultural or Other Restraints. +We seek to increase revenue derived from international sales of our products. Our international sales accounted for $47.3 million or 31% of consolidated net revenues in 2019, $44.9 million or 25% of consolidated net revenues in 2018 and $45.6 million or 27% of consolidated net revenues in 2017. In addition, our subsidiary DNAG, which accounted for $70.2 million or 45% of consolidated net revenues in 2019, is operated in Canada. We also recently acquired Novosanis, a company based in Belgium, and we may acquire other foreign companies as part of our business development efforts. +23 +A number of factors could adversely affect the performance of our business and/or cause us to incur substantially increased costs because of our international presence and sales, including those set forth below: +• +Uncertainty in the application of foreign laws and the interpretation of contracts with foreign parties; +• +The potential for inconsistent imposition of legal and regulatory requirements; +• +Cultural and political differences that favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; +• +Cultural and language differences that make international operations and business management more difficult; +• +Inexperience in international markets and territories and difficulties in staffing and managing foreign operations; +• +Exchange rates, currency fluctuations, tariffs and other barriers, extended payment terms and dependence on international distributors or representatives; +• +Regulatory requirements, including compliance with applicable customs regulations and the need to obtain or maintain regulatory approvals, registrations or reimbursement approvals for our products; +• +Trade protection measures, additional trade sanctions and import/export licensing requirements; +• +The inability to obtain or maintain ISO certification for our or our suppliers’ manufacturing facilities; +• +Our inability to identify international distributors and negotiate acceptable terms for distribution agreements; +• +Diversion to the U.S. of our products that are sold at lower prices into international markets; +• +The loss of one or more distributors and difficulties or delays in obtaining new or transferred product registrations or approvals for use by a replacement distributor; +• +Multiple jurisdictions and differing tax laws, as well as changes in those laws; +• +An increase of withholding and other taxes on remittances and other payments by a foreign subsidiary; +• +The creditworthiness of foreign distributors and customers and difficulty in collecting foreign accounts receivable; +• +Difficulty of enforcing contractual obligations or recovering damages under foreign legal systems; +• +Difficulty collecting amounts owed by foreign governments or other customers; +• +Economic conditions, political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign countries; +• +Exposure to infectious disease and epidemics, including the effects of the coronavirus outbreak on our business operations in geographic locations impacted by the outbreak and on the business operations of our customers and suppliers; +• +Long sales cycles in international markets, especially for sales to foreign governments, quasi-governmental agencies and international public health agencies; +• +The sale of competing products by foreign competitors at prices at or below the prices we offer for our products; +• +Restrictions on our ability to repatriate investments and earnings from foreign operations; +• +Changes in shipping costs; +• +The unavailability of licenses to certain patents in force in a foreign country which cover our products; and +• +Reduced protection for, or enforcement of, our patents and other intellectual property rights in foreign countries. +In addition, we have contracted with a third party in Thailand for the manufacture of a portion of our OraQuick ® tests, and all of DNAG’s products are produced in Canada. We may enter into agreements to manufacture these or other products in additional foreign countries as well. However, economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the United States. Interruption of the supply of our products could reduce revenues or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign countries could also increase the costs of manufacturing our products in foreign countries. In addition, the ongoing coronavirus outbreak emanating from China has resulted in increased government-imposed travel restrictions and extended shutdowns of certain businesses in the affected locations. These or any further political or governmental responses to pandemic diseases could result in social, economic and labor instability of foreign countries, which could have a material adverse effect on our business, results of operations and financial condition. +24 +Our U.S. Government Contracts Require Compliance With Numerous Laws and Increases Our Risk and Liability. +From time to time, we receive funding from the U.S. government and we sell some of our products to the federal government. As a result of our U.S. government funding and product sales to the U.S. government, we must comply with laws and regulations relating to the award, administration and performance of U.S. government contracts. U.S. government contracts typically contain a number of extraordinary provisions that would not typically be found in commercial contracts and which may create a disadvantage and additional risks to us as compared to competitors that do not rely on government contracts. As a U.S. government contractor, we are subject to increased risks of investigation, criminal prosecution and other legal actions and liabilities to which purely private sector companies are not. The results of any such actions could adversely impact our business and have an adverse effect on our consolidated financial performance. +A violation of specific laws and regulations could result in the imposition of fines and penalties or the termination of our contracts, as well as suspension or debarment. The suspension or debarment in any particular case may be limited to the facility, contract or subsidiary involved in the violation or could be applied to our entire enterprise in certain severe circumstances. Even a narrow scope suspension or debarment could result in negative publicity that could adversely affect our ability to renew contracts and to secure new contracts, both with the U.S. government and private customers, which could materially and adversely affect our business and results of operations. Fines and penalties could be imposed for failing to follow procurement integrity and bidding rules, employing improper billing practices or otherwise failing to follow rules relating to billing on cost-plus contracts, receiving or paying kickbacks, or filing false claims, among other potential violations. In addition, we could suffer serious reputational harm and the value of our common stock could be negatively affected if allegations of impropriety related to such contracts are made against us. +Our U.S. Government Contracts May Affect our Intellectual Property Rights. +Provisions in our U.S. government contracts may affect our intellectual property rights. Certain of our activities have been funded, and may in the future be funded, by the U.S. government, including our contracts with the Biomedical Advanced Research and Development Authority (“BARDA”). When new technologies are developed with U.S. government funding, the government obtains certain rights in any resulting patents, including the right to a nonexclusive license authorizing the government to use the invention. These rights may permit the government to disclose our confidential information to third parties and to exercise “march-in” rights to use and allow third parties to use our patented technology. The government can exercise its march-in rights if it determines that action is necessary because we fail to achieve practical application of the U.S. government-funded technology, because action is necessary to alleviate health or safety needs, to meet requirements of federal regulations, or to give preference to U.S. industry. In addition, government-funded inventions must be reported to the government, government funding must be disclosed in any resulting patent applications, and our rights in such inventions may be subject to certain requirements to manufacture products in the United States. +Our U.S. Government Contracts and Related Administrative Processes Are Subject to Audits and Cost Adjustments by the Federal Government. +Federal government agencies can audit and investigate government contracts and the administrative processes and systems of government contractors. These agencies can review our performance on government contracts, pricing practices, cost structure, and compliance with applicable laws, regulations and standards. They can also review our compliance with government regulations and policies and the adequacy of our internal control systems and policies, including our purchasing, accounting, estimating, compensation and management information processes and systems. Any costs found to be improperly allocated to a specific government contract, unallowable or unreasonable will not be reimbursed, and any such costs already reimbursed may be required to be refunded and certain penalties may be imposed. Adjustments arising from government audits and reviews could have a material adverse effect on our business, financial condition, results of operations and prospects. +Moreover, if any administrative process or system related to such contracts is found not to comply with governmental requirements, we may be subjected to government scrutiny that could delay or otherwise adversely affect our ability to compete for or perform government contracts or collect our revenue in a timely manner. An unfavorable outcome of an audit of our government contracts could adversely affect our results of operations. +Risks Relating to Our Industry, Business and Strategy +Our Ability to Sell Products Could be Adversely Affected by Competition From New and Existing Products and Services. +The markets we serve are highly competitive and rapidly changing and we expect competition to intensify as technological advances are made and become more widely known, and as new products and services reach the market. Many of our principal competitors have considerably greater financial, technical and marketing resources than we do. As new products and services enter the market, our products and services may become obsolete or a competitor’s products and services may be more effective or attractive or more +25 +effectively marketed and sold than ours. In addition, there can be no assurance that our competitors will not succeed in obtaining regulatory approval for new products and services that would render our technologies , products and services obsolete or otherwise commercially unattractive, or introduce or commercialize such products and services before we can do so. If we fail to convince our customers of the advantages and economic value of our products and services or otherwise maintain and enhance our competitive position, our customers may decide to use products and services developed by competitors which could result in a loss of revenues. These developments could have a material adverse effect on our business, financial condition and results of operations. +We also face competition from products that are sold at a lower price. Where this occurs, customers may choose to buy lower cost products from third parties or we may be forced to sell our products at a lower price, both of which could result in a loss of revenues or a lower gross margin contribution from the sale of our products. We may also be required to increase our marketing efforts in order to compete effectively, which would increase our costs. +Consolidation in the Healthcare Industry Could Adversely Affect Our Future Revenues and Operating Results. +The healthcare industry has experienced a significant amount of consolidation. As a result of this consolidation, competition to provide goods and services to customers has increased. In addition, group purchasing organizations and integrated health delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. We may not be able to compete successfully in such a consolidated industry. We believe industry consolidation may continue as companies attempt to strengthen or hold their market positions and as more companies are acquired or cease operating. Further consolidation in the industry could exert additional pressure on the prices of our products. +Our Research, Development and Commercialization Efforts May Not Succeed and Our Competitors May Develop and Commercialize More Effective or Successful Offerings. +In order to remain competitive, we must regularly commit substantial resources to research and development and the commercialization of new or enhanced products and services. The research and development process generally takes a significant amount of time from inception to commercial launch. This process is conducted in various stages. During each stage there is a substantial risk that we will not achieve our goals on a timely basis, or at all, and we may have to abandon a new or enhanced product or service in which we have invested substantial time and money. +Successful products and services can require significant development and investment, including testing to demonstrate their performance capabilities, cost-effectiveness or other benefits prior to commercialization. Regulatory approval must be obtained before most products may be sold and additional development efforts on these products may be required before any regulatory authority will review them. Similarly, regulatory clearances or registrations, such as a CLIA certification, and compliance with industry guidelines, may be required in order to provide competitive laboratory services. As noted above, regulatory authorities may not issue such approvals, clearances or certifications or may substantially delay or condition such action. Even if a product or service is developed and all applicable regulatory approvals, clearance or certifications are obtained, there may be little or no market for the product or service and entry into or development of new markets for our products and services may require an investment of substantial resources, such as new employees, offices and manufacturing facilities. Moreover, we may spend a significant amount of money on manufacturing facilities, advertising or other activities and fail to develop a market for the product or service. Other factors that could affect the success of our efforts include our ability to manufacture products or provide laboratory services in a cost-effective manner and whether we can obtain necessary intellectual property rights and protection in the markets where the product or service is sold. +Accordingly, if we fail to develop and gain commercial acceptance for our products and services, or if competitors develop more effective products and services or a greater number of successful new products and services, customers may decide not to purchase our products and services or may purchase and use products and services developed by our competitors. This would result in a loss of revenues and adversely affect our results of operations, cash flow and business. +Failure to Achieve Our Financial and Strategic Objectives Could Have a Material Adverse Impact on Our Business Prospects. +As a result of any number of risk factors identified in this Annual Report, no assurance can be given that we will be successful in implementing our financial and strategic objectives, including our efforts to increase sales of our products and services or continue growing our business. In addition, the funds for research, clinical development and other projects have in the past come primarily from our business operations. If our business slows and we have less money available to fund research and development and clinical programs, we will have to decide at that time which programs to cut, and by how much. Similarly, if adequate financial, personnel, equipment or other resources are not available, we may be required to delay or scale back our business. Our operations will be adversely affected if our total revenue and gross profits do not correspondingly increase or if our technology, product, service, clinical +26 +and market development efforts are unsuccessful or delayed. Furthermore, our failure to successfully introduce new or enhanced products and services and develop new markets could have a material adverse effect on our business and prospects. +If We Lose Our Key Personnel or Are Unable to Attract and Retain Qualified Personnel as Necessary, Our Business Could be Harmed. +Our success depends to a large extent upon the contributions of our executive officers, management and sales, marketing, operations and scientific staff. Our business may be harmed by the loss of a significant number of our executive officers or senior managers. We may not be able to attract or retain a sufficient number of qualified employees in the future due to the intense competition for qualified personnel among medical products, laboratory services and other life science businesses. Our ability to recruit such employees will depend on a number of factors, including compensation, benefits, work location, the prospects of our Company, and the possibility for advancement within our organization. We generally do not enter into employment agreements requiring our employees to work for us for any specified period. +If we are not able to attract and retain the necessary personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively market and sell our products and services, to meet the demands of our strategic partners in a timely fashion, or to support research, development and clinical programs. Although we believe we will be successful in attracting and retaining qualified personnel, competition for experienced scientists and other qualified personnel from numerous companies and academic and other research institutions may limit our ability to do so on acceptable terms. +Acquisitions or Investments May Not Generate the Expected Benefits and Could Disrupt Our Ongoing Business, Distract Our Management, Increase Our Expenses and Adversely Affect Our Business. +Since the beginning of 2019, we have acquired several companies through which we have gained access to new technologies, products and services which are complementary to our existing business and aligned with our long-term business strategy. We will likely continue to pursue strategic acquisitions or investments as a way to expand our business. These activities, and their impact on our business, are subject to many risks, including the following: +• +Suitable acquisitions or investments may not be found or consummated on terms or schedules that are satisfactory to us or consistent with our objectives; +• +We may be unsuccessful in competing for acquisitions with other entities, some of which have greater financial resources or may be better able to realize synergies with a potential target; +• +The benefits expected to be derived from an acquisition or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our inexperience with new businesses or markets, general economic conditions and increased competition; +• +We may be unable to successfully integrate an acquired company’s personnel, assets, management, information technology systems, accounting policies and practices, products, services and/or technology into our business; +• +Worse than expected performance of an acquired business may result in the impairment of intangible assets; +• +Acquisitions may require substantial expense and management time and could disrupt our business; +• +We may not be able to accurately forecast the performance or ultimate impact of an acquired business; +• +We may have difficulties in coordinating geographically separate organizations; +• +We may fail to successfully manage relationships with customers, distributors and suppliers of an acquired business; +• +An acquisition may result in a diversion of resources from our existing products, business and technologies; +• +An acquisition and subsequent integration activities may require greater capital and other resources than originally anticipated at the time of acquisition; +• +An acquisition may result in employee anxiety, morale and/or engagement issues; +• +An acquisition may result in disparate information technology, internal control, financial reporting and record-keeping systems; +• +An acquisition may result in new partners or customers who may operate on terms and programs different than ours; +• +An acquisition may result in employees not familiar with our operations; +27 +• +An acquisition may result in new products and services , including the risk that any underlying intellectual property associated with such products and services may not have been adequately protected or that such products and services may infringe on the proprietary rights of others ; +• +An acquisition may result in the incurrence of unexpected expenses, stockholder lawsuits, the dilution of our earnings or our existing stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the acquired business; +• +An acquisition may result in the loss of our or the acquired company’s key personnel, customers, distributors or suppliers; and +• +An acquisition of a foreign business may involve additional risks, including, but not limited to, foreign currency exposure, liability or restrictions under foreign laws or regulations, and our inability to successfully assimilate differences in foreign business practices or overcome language or cultural barriers and other inherent risks of operating in unfamiliar legal and regulatory environments. +The occurrence of one or more of the above or other factors may prevent us from achieving all or a significant part of the benefits expected from an acquisition or investment. This may adversely affect our financial condition, results of operations and ability to grow our business or otherwise achieve our financial and strategic objectives. +Risks Relating To Our Acquisitions of CoreBiome, Diversigen and Novosanis. +The integration of the CoreBiome, Diversigen and Novosanis businesses may be more difficult, costly or time consuming than expected, and the anticipated benefits and cost savings of these acquisitions may not be realized in full or at all. +The success of the CoreBiome, Diversigen and Novosanis acquisitions will depend, in part, on our ability to successfully combine and integrate our legacy business with the businesses of CoreBiome, Diversigen and Novosanis. The integration of CoreBiome, Diversigen and Novosanis’ businesses with our existing business and the integration of the CoreBiome and Diversigen laboratory operations are each complex, costly and time-consuming processes. It is possible that a number of factors, including, without limitation, the loss of key employees, higher than expected costs, diversion of management attention and resources, the disruptions of ongoing businesses or inconsistencies in standards, controls, procedures and policies, could adversely affect our ability to maintain relationships with customers, vendors and employees or to achieve the anticipated benefits and cost savings of the acquisitions. If we experience difficulties with the integration process, the anticipated benefits of the CoreBiome, Diversigen and Novosanis acquisitions may not be realized fully or at all, or may take longer to realize than expected. These integration matters could have an adverse effect on the Company for an undetermined period following the acquisitions. +As a general matter, the market for microbiome laboratory testing and analytical services provided by CoreBiome and Diversigen is at an early stage and is still developing. In addition, the Colli-Pee ® urine collection devices manufactured and sold by Novosanis are relatively new products that are not yet widely accepted by customers. Although we are optimistic about the prospects for these new businesses, there is no assurance that we will be successful in creating or expanding demand for these services and products. To the extent that the markets for these services and products fail to develop or increase, our revenues and results of operations could be adversely affected and we may not meet our growth objectives. +The Future results of the Combined Companies May Be Adversely Impacted if We Do Not Effectively Manage Our Expanded Operations . +Following the completion of the CoreBiome, Diversigen and Novosanis acquisitions, the size of our business has increased and these acquisitions are expected to enhance our growth in future periods. Our ability to successfully manage this expanded business will depend, in part, upon management’s ability to design and implement strategic initiatives that address not only the integration of the two companies, but also the increased scale and scope of the combined businesses with its associated increased costs and complexity. There can be no assurances that we will be successful and the CoreBiome, Diversigen and Novosanis acquisitions may have an adverse effect on the Company. +Our Revenues Could be Affected by Third-Party Reimbursement Policies and Potential Cost Constraints. +The end-users of certain of our products include hospitals, physicians and other healthcare providers. Use of our products could be adversely impacted if these end-users do not receive adequate reimbursement for the cost of our products from their patients’ healthcare insurers or payors. Our net sales could also be adversely affected by changes in reimbursement policies of governmental or private healthcare payors, including in particular the level of reimbursement for our products. +28 +In the United States, hospitals, physicians and other healthcare providers who purchase diagnostic products generally rely on third-party payors, such as private health insurance plans, Medicare and Medicaid, to reimburse all or part of the cost of the product and procedure. The overall escalating cost of medical products and services has led to, and will continue to lead to, increased pressures on the healthcare industry, both foreign and domestic, to reduce the cost of products and services. Given the efforts to control and reduce healthcare costs in the United States in recent years, currently available levels of reimbursement may not continue to be available in the future for our existing products or products under development. Third-party reimbursement and coverage may not be available or adequate in either the United States or international markets, current reimbursement amounts may be decreased in the future and future legislation, and regulation or reimbursement policies of third-party payors, may reduce the demand for our products or our ability to sell our products on a profitable basis. In addition, the reimbursement approval process may delay the market introduction of our products. +Changes in Healthcare Regulation Could Affect Our Revenues, Costs and Financial Condition. +In recent years, there have been numerous initiatives at the federal and state level for comprehensive reforms affecting the payment for, the availability of and reimbursement for healthcare services in the United States. These initiatives have ranged from proposals to fundamentally change federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under government-funded programs, to minor modifications to existing programs. One example is the Patient Protection and Affordable Care Act, the Federal healthcare reform law enacted in 2010 (the “Affordable Care Act”). Similar reforms may occur internationally. +Legislative and regulatory bodies are likely to continue to pursue healthcare reform initiatives in many forms and may continue to reduce funding in an effort to lower overall federal healthcare spending. The U.S. government recently enacted legislation that eliminated what is known as the “individual mandate” under the Affordable Care Act and may enact other changes in the future. The ultimate content and timing of any of these types of changes in other healthcare reform legislation and the resulting impact on us are impossible to predict. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise have an adverse effect on our financial condition and results of operations. +New or Changed Testing Guidelines Could Affect Sales of Our Diagnostic Products. +From time to time, governmental agencies such as the Centers for Disease Control and Prevention, or CDC, issue diagnostic testing guidelines or recommendations, which can affect the usage of our HIV and HCV testing products. For example, domestic professional OraQuick ® HIV sales have decreased in recent years in part due to customer migration to automated fourth generation HIV immunoassays performed in a laboratory, as recommended under testing guidelines issued by the CDC. In addition, some states have promulgated, or may in the future promulgate, laws and regulations that affect HIV or HCV testing. The issuance of new laws or guidelines, or changes in existing laws or guidelines, and the manner in which these new or changed laws and guidelines are interpreted and applied by healthcare practitioners, could impact the degree to which our OraQuick ® rapid HIV and HCV testing products or other products are used. New or changed laws or guidelines could affect the number of people tested, the frequency of testing and whether testing products such as our OraQuick ® HIV and HCV tests are used broadly for screening large populations or in a more limited capacity as a confirmatory test or otherwise. These factors could in turn affect the level of sales of our products and our results of operations. +Reductions in Government Funding and Research Budgets Could Adversely Affect Our Business and Financial Results. +We sell our OraQuick ADVANCE ® HIV-1/2 and OraQuick ® HCV tests into the public health market which consists of state, county and other governmental public health agencies, community based organizations, service organizations and similar entities. We also sell these products into the hospital market. Many of these customers depend to a significant degree on grants or funding provided by governmental agencies to run their operations including programs that use our products. In international markets, we often sell products such as our OraQuick ® HIV Self-Test to or through foreign governmental agencies or parties funded by such agencies. +Many of our molecular collection products are sold to researchers at academic institutions, pharmaceutical and biotechnology companies, government laboratories and private foundations. Many research customers are dependent for their funding on grants from U.S. governmental agencies such as the U.S. National Institutes of Health and agencies in other countries to pay for the products and services they purchase. These research customers also purchase our genomic and microbiome laboratory tests and analytical services. +The level of available government grants or funding in the U.S. and elsewhere is unpredictable and may be affected by various factors including economic conditions, legislative and regulatory developments, political changes, civil unrest and changing priorities for research and development activities. Further, government proposals to reduce or eliminate budgetary deficits have sometimes included reduced allocations to government agencies in the U.S. and other countries that fund life sciences research and development activities. +29 +Any reduction or delay in government or other funding as a result of legislative or regulatory changes or other factors, could cause our customers to delay, reduce or forego purchases of our products and services . +New Tariffs and Other Trade Measures Could Adversely Affect Our Financial Position, Results of Operations and Cash Flows . +The current U.S. Administration has expressed strong concerns about imports from countries that it perceives as engaging in unfair trade practices, and it is possible the administration could impose import duties or other restrictions on products, components or raw materials sourced from those countries, which may include countries from which we import components or raw materials. Any such import duties or restrictions could have a material adverse effect on our business, results of operations or financial condition. Moreover, these new tariffs, or other changes in U.S. trade policy, could trigger retaliatory actions by affected countries. Certain foreign governments have instituted or are considering imposing trade sanctions on certain U.S. goods. +Other foreign governments are considering the imposition of sanctions that will deny U.S. companies access to critical raw materials. A “trade war” of this nature or other governmental actions related to tariffs or international trade agreements or policies has the potential to adversely impact demand for our products, our costs, customers, suppliers and/or the economic environments in which we operate and, thus may adversely impact our businesses. Recent international events have introduced greater uncertainty with respect to trade wars and tariffs, which may affect trade between the United States and other countries, particularly with China. On January 15, 2020, the United State and China signed a “Phase One” deal in the ongoing trade war, resulting in suspension of a second tranche of certain duties. +In addition, the U.S., Mexico and Canada have negotiated and reached an agreement on the U.S. Mexico Canada Agreement (the “USMCA”), the successor agreement to the North American Free Trade Agreement (“NAFTA”). The USMCA maintains duty-free access for most products and leaves most key provisions of NAFTA largely intact. As of the date of this report, the USMCA still needs to be ratified by Canada before going into force. It remains unclear whether Canada will ratify the USMCA. Any changes to USMCA could impact our operations in countries where we manufacture or sell products or source components, or materials, which could adversely affect our operating results and our business. For example, changes in the level of reimbursement or the availability of funding for health care could create uncertainty for our business and negatively impact or revenues and results of operations. Similarly, a substantial part of DNAG’s revenues represent sales of product from Canada to the U.S. The imposition of tariffs or other changes in the trade relationship between Canada and the United States could negatively impact DNAG’s performance. +The United Kingdom’s Decision to Leave the EU Could Adversely Affect Us. +In June 2016, a majority of voters in the United Kingdom (“U.K.”) elected to withdraw from the EU in a national referendum (“Brexit”). Although the U.K. officially left the EU on January 31, 2020, the withdrawal agreement setting forth the terms of the U.K.’s departure allows for a transition period during which the U.K.’s trading relationship with the EU will remain largely unchanged. The transition period is due to end on December 31, 2020. During this transition period, the U.K. and the EU will continue to negotiate the details of their future relationship, including trade, tariff, financial services and security cooperation. +If no agreement is reached between the U.K. and the EU by the end of the transition period, it will likely have an adverse impact on labor and trade in addition to creating further short-term uncertainty and currency volatility. In the absence of a future trade deal, the U.K.’s trade with the EU and the rest of the world would be subject to tariffs and duties set by the World Trade Organization. Additionally, the movement of goods between the U.K. and the remaining member states of the EU will be subject to additional inspections and documentation checks, leading to possible delays at ports of entry and departure. These changes to the trading relationship between the U.K. and EU would likely result in increased costs of goods imported into and exported from the U.K. +At this time, the impact of Brexit remains uncertain and will depend, in part, on the final outcome of the negotiations between the U.K. and the EU. Our business in the U.K., the EU and world-wide could be affected during this period of uncertainty, and perhaps longer, by the impact of Brexit. Brexit has led to, and could further cause, volatility in global financial markets, including in global currency exchange rates, resulting in a slow-down in economic activity in the U.K., Europe or globally, negatively impact new trade agreements between the U.K and other countries, including the United States, and result in significant regulatory changes and uncertainty. One or more of these events could make it more difficult or costly to sell our products, particularly in the U.K. and Europe, and negatively affect our revenues and results of operations. Brexit may also influence other countries and result in additional countries deciding to leave the EU. This in turn could result in additional changes and uncertainty, any or all of which could negatively impact our business. +30 +Increases in Demand for Our Products and Services Could Require Us to Expend Considerable Resources or Harm Our Customer Relationships if We are Unable to Meet That Demand. +If we experience significant or unexpected increases in the demand for our products and services, we and our suppliers may not be able to meet that demand without expending additional capital resources. These capital resources could involve the cost of new products, machinery or new manufacturing or laboratory facilities. This would increase our capital costs, which could adversely affect our earnings. Our suppliers may be unable or unwilling to expend the necessary capital resources or otherwise expand their capacity. In addition, new manufacturing or laboratory equipment and facilities may require FDA approval or government or industry certification before they can be used to manufacture our products or provide laboratory services. To the extent we are unable to obtain or are delayed in obtaining such approvals, our ability to meet the demand for our products and services could be adversely affected. +If we are unable to develop necessary manufacturing or laboratory capabilities in a timely manner, our sales could be adversely affected. If we fail to increase these capabilities in a cost effective manner or if we experience lower than anticipated yields or production or performance problems as a result of changes that we make in our manufacturing or laboratory processes to meet increased demand, we could experience delays or interruptions and increased costs, which could also have a material adverse effect on our revenues and profitability. +Unexpected increases in demand for our products may require us to obtain additional raw materials in order to manufacture products to meet the demand. Some raw materials require significant ordering lead time and some are currently obtained from a sole supplier or a limited group of suppliers. We have long-term supply agreements with certain of these suppliers, but these long-term agreements involve risks for us, such as our potential inability to obtain an adequate supply of raw materials and components and our reduced control over pricing, quality and timely delivery. It is also possible that one or more of these suppliers may become unwilling or unable to deliver materials to us. Any shortfall in our supply of raw materials and components, or our inability to quickly and cost-effectively obtain alternative sources for this supply, could have a material adverse effect on our ability to meet increased demand for our products. This could negatively affect our total revenues or cost of sales and related profits. +Our inability to meet customer demand for our products and services could also harm our customer relationships and impair our reputation within the industry. This, in turn, could have a material adverse effect on our business and prospects. +We Rely on Information Technology in Our Operations and Any Material Failure, Inadequacy, Interruption or Security Breach of that Technology Could Harm Our Ability to Efficiently Operate Our Business. +We rely heavily on enterprise resource planning and other complex information technology systems across our operations and on the internet, including for management of inventory, processing and analyzing laboratory specimens, purchase orders, invoices, shipping, revenue and expense accounting, online business, consumer call support, and various other processes and transactions. Our ability to effectively manage our business, coordinate the production, distribution and sale of our products, process and analyze specimens in our laboratories, respond to customer inquiries, and ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these systems and the internet. +The failure of any of the foregoing systems to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the operation of the internet, could cause delays in product sales or the provision of laboratory services and reduced efficiency of our operations. Significant expenditures could be required to remediate any such problem. +Security Breaches and Other Disruptions Could Compromise Our Information, Expose Us To Liability and Harm Our Reputation and Business. +In the ordinary course of our business, we collect and store sensitive data, including intellectual property, personal information, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees in our data centers and on our networks. Secure maintenance and transmission of this information is critical to our operations business strategy. We generally rely on commercially available systems, software, tools and domestically available monitoring to provide security for processing, transmitting and storing this sensitive date. +Cyber-attacks could result in unauthorized access to our computer systems or our third party IT service provider’s systems and, if successful, misappropriate personal or confidential information. Spear phishing has occurred and is a growing threat that the Company is facing. If successful, these activities could lead to the disclosure of intellectual property or personally identifiable information, which could lead to financial harm and cause reputational damage. We have taken additional steps designed to improve the security of our networks and computer systems. +31 +In addition, a contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or inadvertently cause a breach involving sensitive information. While we will continue to evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, cyberattacks are becoming more sophisticated and frequent and the techniques used in such attacks change rapidly. Despite our cybersecurity measures (including employee and third party training, monitoring of networks and systems and maintenance of back up of protective systems) which are continuously reviewed and upgraded, our information technology networks and infrastructure may still be vulnerable to damage, disruptions or shut downs due to attack by hackers or breaches, voyeur or malfeasance. +Even the most well protected IT networks, systems and facilities remain potentially vulnerable because the techniques used in attempted security breaches are continually evolving and generally are not recognized until launched against a target or, in some cases, are designed not to be detected and, in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of personal or confidential business information, could result in legal claims and proceedings, liability under laws to protect privacy of personal information, and regulatory penalties, and could disrupt our operations, require significant management attention and resources to remedy any damages that result, and damage our reputation and customers willingness to transact business with us, any of which could adversely affect our business. +As our activities continue to evolve and expand, we may be subject to additional laws which impose further restrictions on the transfer, access, use, and disclosure of health and other personal information which may impact our business either directly or indirectly. Our failure to comply with applicable privacy or security laws or significant changes in these laws could significantly impact our business and future business plans. +Risks Relating to Collaborators +The Use of Third Party Supply Sources For Critical Components of Our Products Could Adversely Affect Our Business. +We currently purchase certain critical components of our products from sole supply sources or other third-party suppliers. For example, the biological antigens and antibodies, nitrocellulose and certain other components required to make our OraQuick HIV, HCV and Ebola products are currently purchased from sole source suppliers. Our OraSure QuickFlu ® test and the fully automated high-throughput drug assays sold with our Intercept i2 ® device are manufactured and supplied by sole source suppliers and the conjugates used in our MICROPLATE oral fluid drugs-of-abuse assays are obtained from third-party suppliers. +We have contracted with a third party in Thailand for the assembly of OraQuick ® HIV device and the OraQuick ® HIV Self-Test in order to supply certain international markets. In addition, our subsidiary, DNAG, uses two third-party manufacturers to supply virtually all of its products, including its Oragene ® line of collection kits. Many of the raw materials and components used in its products are also purchased from third parties, a critical one of which is obtained from a sole source supplier. +If our third-party suppliers are unable or unwilling to supply or manufacture a required component or product or if they make changes to a component, product or manufacturing process or do not supply materials meeting our specifications, we may need to find another source and/or manufacturer. This could require that we perform additional development work and it may be difficult to find such an alternate supply source in a reasonable time period or on commercially reasonable terms, if at all. We may also need to obtain FDA or other regulatory approvals for the use of an alternative component or for changes to our products or manufacturing process. Completing that development and obtaining such approvals could require significant time and expense and such approvals may not occur at all. The availability of critical components and products from sole supply sources or other third parties could also reduce our control over pricing, quality and timely delivery. These events could either disrupt our ability to manufacture and sell certain of our products into one or more markets or completely prevent us from doing so, and could increase our costs. Any such event could have a material adverse effect on our results of operations, cash flow and business. +Our Failure to Maintain Existing Distribution Channels, or Develop New Distribution Channels, May Result in Lower Revenues. +We have marketed many of our products by collaborating with laboratories, diagnostic companies and distributors. Our sales depend to a substantial degree on our ability to sell products to these customers and on the marketing and distribution abilities of the companies with which we collaborate. +Relying on distributors or others to market and sell our products could harm our business for various reasons, including: +• +We may not be able to find suitable distributors to distribute our products on satisfactory terms, or at all; +32 +• +Our distributors or other customers may not fulfill their contractual obligations to us or otherwise market and distribute our products in the manner or at the levels we expect; +• +We do not control the incentives provided by our distributors to their sales personnel and the effectiveness of these incentives could affect sales of our products; +• +Agreements with distributors may terminate prematurely due to disagreements or may result in litigation between the parties; +• +We may not be able to renew existing distribution agreements on acceptable terms, or at all; +• +Our distributors may not devote sufficient resources or priority to the sale of our products; +• +Our distributors may prioritize their own private label products that compete with our products; +• +Our existing distributor relationships or contracts may preclude or limit us from entering into arrangements with other distributors; and +• +We may not be able to negotiate future distribution agreements on acceptable terms, or at all. +Although we will try to maintain and expand our business with distributors and customers and require that they fulfill their contractual obligations, there can be no assurance that such companies will do so or that new distribution channels will be available on satisfactory terms. As a result, our revenues and business could be adversely affected. +We May Need Strategic Partners to Assist in Developing and Commercializing Some of Our Products. +Although we may elect to pursue some product opportunities independently, opportunities that require a technology controlled by a third party, a significant level of investment for development and commercialization or a distribution network beyond our existing sales force may necessitate involving one or more strategic partners. Further, our ability to enter into agreements with additional strategic partners depends in part on convincing them that our products can help achieve and accelerate their goals and efforts. Our strategy for development and commercialization of products may entail entering into arrangements with distributors or other corporate parties, universities, research laboratories, government agencies, licensees and others. Relying on collaborative relationships could be risky to our business for a number of reasons, including: +• +We may be required to transfer material rights to such strategic collaborators, government agencies, licensees and others; +• +Our collaborators may not devote sufficient resources or attach a sufficiently high priority to the success of our collaboration; +• +Our collaborators may not obtain regulatory approvals necessary to continue the collaborations in a timely manner; +• +We have limited access to our collaborator’s confidential corporate information and sudden unexpected changes in ownership or strategy or other material events affecting a collaborator of which we are not currently aware could adversely impact our relationship; +• +Our collaborators may be acquired by another company, decide to terminate our collaborative arrangement or become insolvent; +• +Our collaborators may develop technologies or components competitive with our products; +• +Our collaborators may fail to deliver technologies or components that satisfy market requirements or such products may fail to perform properly; +• +Disagreements with collaborators could result in the termination of the relationship or litigation; +• +Collaborators may not have sufficient capital resources; and +• +We may not be able to negotiate future collaborative arrangements, or renewals of existing collaborative agreements, on acceptable terms or at all. +While we generally expect that our collaborative partners will have an economic motivation to succeed in performing their contractual responsibilities, there is no assurance that they will do so, either at the level required or at all, and the amount and timing of resources to be devoted to these activities will be controlled by others. Reliance on strategic agreements can also make it difficult to accurately forecast our future revenues operating results. There can be no assurance that the expected revenues or profits will be fully derived from such arrangements. +33 +Risks Relating to Intellectual Property +Our Success Depends on Our Ability to Protect Our Proprietary Technology. +Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property rights, for new technologies, products and processes. Our success depends, in part, on our ability to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and in other countries. If we cannot continue to develop, obtain and protect intellectual property rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other technologies may not be adequate for the operation of our business. +As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents will cover, as applicable, compositions of matter for our products, methods of making those products, methods of using those products and apparatuses relating to the use or manufacture of those products. +We also rely on trade secrets, know-how and continuing technological advancements to protect our proprietary technology. We have entered, and will continue to enter, into confidentiality agreements with our employees, consultants, advisors and collaborators. Our employees and third-party consultants also sign agreements requiring that they assign to us interests in inventions and original expressions and any patents or copyrights arising from their work. However, these parties may not honor these agreements. +We cannot guarantee that the process of filing patents, the laws governing trade secrets and proprietary information, or any agreements we enter into with employees, consultants, advisors or collaborators will provide adequate protection of our intellectual property rights. For example, our competitors may develop similar products without infringing on any of our intellectual property rights or design around our proprietary technologies. Employees, consultants and others who participate in the development of our products may breach their agreements with us regarding our intellectual property, and we may not have adequate remedies for the breach. We also may not be able to effectively protect our intellectual property rights in some foreign countries, as many countries do not offer the same level of legal protection for intellectual property as the United States. +For a variety of reasons, we may decide not to file for patent, copyright or trademark protection outside of the U.S. Our trade secrets could become known through other unforeseen means. Although we have licensed certain technology for use in our microbiome laboratory services offerings and we have developed proprietary know-how that we use in this business, we do not currently hold any patents covering the laboratory processes and analytical methods offered to our customers. The absence of patent protection in this or other parts of our business may make it more difficult to protect our intellectual property. In addition, our competitors may independently develop similar or alternative technologies or products that are equal or superior to our technology. +Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents expire, we may be faced with increased competition, which could reduce our revenues. We may also not be able to successfully protect our rights to unpatented trade secrets and know-how. +Some of our employees, including scientific and management personnel, were previously employed by competing companies. Although we encourage and expect all of our employees to abide by any confidentiality agreement with a prior employer, competing companies may allege trade secret violations and similar claims against us. In addition, some of these agreements may conflict with, or be subject to, the rights of third parties with whom our employees, consultants or advisers have prior employment or consulting relationships. An adverse determination may limit or restrict the type of work that certain employees involved with such products may perform. +We may collaborate with universities and governmental research organizations or receive funding for our products from government agencies. As a result, one or more of these entities may acquire part of the rights to any inventions or technical information derived from our collaboration or funding relationship with them. +To facilitate development and commercialization of a proprietary technology base, we may need to obtain licenses to patents or other proprietary rights from other parties. Obtaining and maintaining such licenses may require the payment of substantial amounts. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. Moreover, some licenses may be nonexclusive, and therefore our competitors may have access to the same technology licensed to us. +34 +We May Become Involved in Intellectual Property Disputes, Which Could Increase our Costs and Limit or Eliminate Our Ability to Sell Products , Provide Services or Use Certain Technologies. +From time to time, we may seek to enforce our patents or other intellectual property rights through litigation. In addition, there are a large number of patents and patent applications in our product and service areas, and additional patents may be issued to third parties relating to our product and service areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property rights with respect to one or more of our products or services. Litigation in our industry regarding patent and other intellectual property rights is prevalent and is expected to continue. We may also have disputes with parties that license patents to us if we believe the license is no longer needed for our products or services or the licensed patents are no longer valid or enforceable. +Our industry is characterized by a large number of patents, and the claims of these patents appear to overlap in many cases. As a result, there is a significant amount of uncertainty regarding the extent of patent protection and infringement. Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing, that cover technologies we incorporate in our products or services. Accordingly, we may be subjected to substantial damages for past infringement or be required to modify our products or services or stop selling them if it is ultimately determined that our products or services infringe a third party’s proprietary rights. In addition, governmental agencies could commence investigations or criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. +Intellectual property litigation is costly. As such, our involvement in litigation or other legal proceedings with respect to patents or other intellectual property and proprietary technology, either as a plaintiff or defendant, could adversely affect our revenues, market share, results of operations and business because: +• +As is common with major litigation, it could consume a substantial portion of managerial and financial resources; +• +Its outcome would be uncertain and a court may find that our patents are invalid or unenforceable in response to claims by another party or that the third-party patent claims are valid and infringed by our products or services; +• +An adverse outcome could subject us to the loss of the protection of our patents or to liability in the form of past royalty payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our future earnings; +• +Governmental agencies may commence investigations or criminal proceedings against our employees, former employees and us relating to claims of misappropriation or misuse of another party’s proprietary rights; +• +Failure to obtain a necessary license upon an adverse outcome could prevent us from selling our current products or services or other products or services we may develop or acquire; +• +We may be required to alter our product or services, given the proprietary rights of others; +• +The pendency of any litigation may in and of itself cause our distributors and customers to reduce or terminate purchases of our products or services; and +• +A court could award a preliminary and/or permanent injunction, which would prevent us from selling our current or future products or services. +We may indemnify some customers and strategic partners under our agreements with such parties if our products, services or activities have actually or allegedly infringed upon, misappropriated or misused another party’s proprietary rights. Further, our products or services may contain technology provided to us by other parties, such as universities, contractors, suppliers, customers or collaborators, and we may have little or no ability to determine in advance whether such technology infringes the intellectual property rights of a third party. These other parties may also not be required or financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. +We may also become involved in other types of disputes regarding intellectual property rights, including state, federal or foreign court litigation, and patent interference, patent reexamination, patent reissue, or trademark opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office as well. Under Federal law, various forms of post issuance patent review proceedings have been authorized, including an inter-parties review process. These proceedings permit certain persons to challenge the validity of a patent on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in the loss of valuable patent rights that could have a material adverse effect on our business, financial condition, results of operations and growth prospects. +35 +Regulatory Risks +The Need to Obtain Regulatory Approvals Could Increase Our Costs and Adversely Affect Our Financial Performance. +Many of our proposed and existing products and services are subject to regulation by the FDA and other governmental or public health agencies. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products and the processes and procedure for our laboratory services. Our practice is to train our employees on the legal requirements applicable to our business, including the requirements of the FDA and other relevant agencies. +The process of obtaining required approvals, clearances, premarket authorizations can involve lengthy and detailed laboratory testing, human clinical trials, sampling activities and other costly, time-consuming procedures. These approvals, clearances, other premarket authorizations or certifications can require the submission of a large amount of clinical data which can be expensive and may require significant time to obtain. It is also possible that a product will not perform at a level needed to generate the clinical data required to obtain such premarket authorizations. The submission of an application to the FDA or other regulatory authority does not guarantee that an authorization to market or import the product or a laboratory certification will be received. A regulatory authority may impose requirements as a condition to granting an approval, clearance, premarket authorization or certification that may include significant restrictions or limitations. The regulatory authority may delay or refuse to grant premarket authorization, even though a product has been approved or registered without restrictions or limitations in another country or by another agency. Delays in receipt or failure to receive such approvals, clearances, premarket authorization or certification could have a material adverse effect on our business, financial condition and results of operations. +All in vitro diagnostic products that are to be sold in the EU must bear the CE mark indicating conformance with the essential requirements of the IVDD. We have obtained the CE mark for several of our existing products. We also intend to apply for CE marks for certain of our future products and are not aware of any material reason why we would be unable to obtain those marks. However, there can be no assurance that compliance with all provisions of the IVDD will be demonstrated and the CE mark will be obtained or maintained for all products that we desire to sell in the EU. The failure to obtain or maintain the CE mark for one or more of our products could lead to the termination of strategic alliances and agreements for sales of those products in the EU. +In addition, we or our distributors are often required to obtain premarket authorization or product registration with foreign governments or regulatory bodies before we can import and sell our products in foreign countries. We may also be required to obtain WHO pre-qualification or endorsement in order to sell certain products in international markets or enable our customers to access interested funding sources for our products. We may have difficulty obtaining such authorizations, registrations, pre-qualifications or endorsements and, if obtained, such authorizations, registrations, pre-qualifications or endorsements may contain restrictions that limit our ability to market and sell our products in the relevant country. In addition, any change in our arrangement with a foreign distributor could result in the loss of or delay in transfer of any applicable product registrations, thereby interrupting our ability to sell those products in the affected markets. +Failure to Comply With FDA or Other Regulatory Requirements May Require Us to Suspend Production or Sale of Our Products or Institute a Recall Which Could Result in Higher Costs and a Loss of Revenues. +Regulation by the FDA and other federal, state and foreign regulatory agencies impacts many aspects of our operations, and the operations of our suppliers and distributors, including manufacturing, labeling, packaging, adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other agencies to determine compliance with QSR and FDA regulatory requirements in the United States and other applicable regulations worldwide, including but not limited to ISO standards. We believe that our facilities and procedures are in material compliance with the FDA requirements and ISO standards, but the regulations may be unclear and are subject to change, and we cannot be sure that the FDA or other regulators will agree with our compliance with these requirements. The FDA and foreign regulatory agencies may require post-marketing testing and surveillance to monitor the performance of approved or cleared products or impose conditions on any product clearances or approvals that could restrict the distribution or commercial applications of those products. Regulatory agencies may impose restrictions on our or our distributors’ advertising and promotional activities or preclude these activities altogether if a noncompliance is believed to exist. In addition, the subsequent discovery of previously unknown problems with a product may result in restrictions on the product or additional regulatory actions, including withdrawal of the product from the market. +Failure to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or judicially imposed sanctions such as injunctions, civil penalties, recall or seizure of products, total or partial suspension of production, refusal to grant premarket clearance or PMA approval for devices, withdrawal of product registrations, marketing clearances or approvals, or criminal prosecution. The ability of our suppliers to supply critical components or materials and of our distributors to sell our products could also be adversely affected if their operations are determined to be out of compliance. Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of operations. +36 +Some of our products, particularly those sold by DNAG, are sold for research purposes in the U.S. We do not promote these products for clinical diagnostic use and they are labeled “For Research Use Only”, or RUO. If the FDA were to disagree with our RUO designation of a product, we could be forced to stop selling the product until appropriate regulatory clearance or approval has been obtained. +In the ordinary course of business, we must frequently make subjective judgments with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with the manner in which we have sought to comply with these regulations, we could be subjected to substantial civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. The assessment of any civil and criminal penalties against us could severely impair our reputation within the industry and any limitation on our ability to manufacture and market our products could have a material adverse effect on our business. +Our Inability to Respond to Changes in Regulatory Requirements Could Adversely Affect Our Business. +We believe that our products and procedures are in material compliance with all applicable FDA regulations, ISO requirements, and other applicable regulatory requirements, but the regulations regarding the manufacture and sale of our products, the QSR and ISO requirements, and other requirements may be unclear and are subject to change. Newly promulgated regulations could require changes to our products, necessitate additional clinical trials or procedures, or make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to change the requirements for obtaining product approval and/or impose new or additional requirements as part of the approval process. These changes or new or additional requirements may occur after the completion of substantial clinical work and other costly development activities. The implementation of such changes or new or additional requirements may result in additional clinical trials and substantial additional costs and could delay or make it more difficult or complicated to obtain approvals and sell our products. We cannot predict the effect, if any, that these changes might have on our business, financial condition or results of operations. +Our Inability to Manufacture Products in Accordance With Applicable Specifications, Performance Standards or Quality Requirements Could Adversely Affect Our Business. +The materials and processes used to manufacture our products must meet detailed specifications, performance standards and quality requirements to ensure our products will perform in accordance with their label claims, our customers’ expectations and applicable regulatory requirements. As a result, our products and the materials used in their manufacture or assembly undergo regular inspections and quality testing. Factors such as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events or conditions could cause our products or the materials used to produce or assemble our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. +Any failure or delay in our ability to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our ability to manufacture and sell our products or comply with regulatory requirements. These events could, in turn, adversely affect our revenues and results of operations. +We Are Subject to Numerous Government Regulations in Addition to FDA Requirements, Which Could Increase Our Costs and Affect Our Operations. +In addition to the FDA and other regulations described previously, laws and regulations in some states may restrict our ability to sell products in those states. While we intend to work with state legislators and regulators to remove or modify any applicable restrictions, there is no guarantee we will be successful in these efforts. +We must also comply with numerous laws relating to such matters as safe working conditions, manufacturing practices, environmental protection, fire hazard control, disposal of hazardous substances, labor or employment practices and the configuration and operation of the websites through which we advertise our products. As a device manufacturer, we are required to report annually to the Centers for Medicare & Medicaid Services (“CMS”) any payments or transfers of value we have made to physicians and teaching hospitals and any physician ownership or investment interest in the Company. Compliance with these laws or any new or changed laws regulating our business could result in substantial costs. Because of the number and extent of the laws and regulations affecting our industry, and the number of governmental agencies whose actions could affect our operations, it is impossible to reliably predict the full nature and impact of these requirements. To the extent the costs and procedures associated with complying with these laws and requirements are substantial or it is determined that we do not comply, our business and results of operations could be adversely affected. +37 +Failure to Comply With Privacy, Security and Breach Notification Regulations May Increase Our Costs. +The Company believes it is neither a covered entity nor a business associate of a covered entity and is not responsible for complying with the Health Insurance Portability and Accountability Act of 1996, as amended (“HIPAA”). However, the Company has in place certain administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal information and endeavors to comply with all applicable state and federal laws with respect to the protection of consumers’ personal information. The Company is required to comply with varying state privacy, security and breach reporting laws. If we do not comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal information, we could be subject to monetary fines, civil penalties or criminal sanctions. In addition to other federal and state laws that protect the privacy and security of consumers’ personal information, we may be subject to enforcement and interpretations by various governmental authorities and courts resulting in complex compliance issues. For example, we could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’ personal information. +Failure to Comply With Data Protection Requirements Could Increase Our Costs . +The European Union (“EU”) has adopted a comprehensive overhaul of its data protection regime from the prior national legislative approach to a single European Economic Area Privacy Regulation called the General Data Protection Regulation (“GDPR”), which came into effect on May 25, 2018. The new EU data protection regime extends the scope of the EU data protection law to all foreign companies processing data of EU residents. It provides for a harmonization of the data protection regulations throughout the EU, thereby making it easier for non-European companies to comply with these regulations. It imposes a strict data protection compliance regime with severe penalties of up to the greater of 4% of worldwide turnover and €20 million and includes new rights such as the “portability” of personal data. Although the GDPR will apply across the EU without a need for local implementing legislation, as had been the case under the prior data protection regime, local data protection authorities will still have the ability to interpret the GDPR, which has the potential to create inconsistencies on a country-by-country basis. We are evaluating these new requirements and implementing a plan to ensure compliance. Complying with the enhanced obligations imposed by the GDPR may result in significant costs to our business and require us to amend certain of our business practices. Further, we have no assurances that violations will not occur, particularly given the complexity of the GDPR, as well as the uncertainties that accompany new, comprehensive legislation. +We are also subject to the California Consumer Privacy Act of 2018 (“CCPA”), which took effect on January 1, 2020. The CCPA imposes extensive new requirements and protections on the processing of personal data, aimed at giving California consumers more visibility and control over their personal information. Failure to comply with the CCPA or other data processing or security laws, or any changes in these laws, could adversely impact our business and our business plans. +Compliance With Regulations Governing Public Company Corporate Governance and Reporting is Complex and Expensive. +Many laws and regulations impose obligations on public companies, and these obligations have increased the scope, complexity and cost of corporate governance, reporting and disclosure practices. Examples include the Sarbanes-Oxley Act of 2002, the requirements of The NASDAQ Global Market, The Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC’s requirements for public companies to provide financial statements in interactive data format using the eXtensible Business Reporting Language (“XBRL”), and the International Financial Reporting Standards conversion requirements. Our implementation of certain aspects of these laws and regulations has required and will continue to require substantial management time and oversight and may require us to incur significant additional accounting and legal costs. We continually evaluate and monitor developments with respect to new and proposed rules and cannot predict or estimate the ultimate amount of additional costs we may incur or the timing of such costs. These laws and regulations are also subject to varying interpretations, in many cases due to their lack of specificity, and as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices. Although we are committed to maintaining high standards of corporate governance and public disclosure, if we fail to comply with any of these requirements, legal proceedings may be initiated against us, which may adversely affect our business. +FDA Regulation of Laboratory-Developed Tests and Genetic Testing Could Affect Demand For Our Products. +The FDA has regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories. In the past, the FDA has taken the position that it has regulatory authority over laboratory-developed tests, or LDTs, but has exercised enforcement discretion in not regulating most LDTs performed by high complexity CLIA-certified laboratories. LDTs are tests designed, developed, and performed in-house by a laboratory. Such laboratories are subject to regulation under CLIA but have not been subject to regulation by FDA under the agency’s medical device requirements. A significant portion of the total volume of genetic or molecular testing is performed with LDTs. +In mid-2010, the FDA announced that it would begin regulating LDTs, including laboratory developed molecular tests, and in October 2014 issued proposed guidance on the regulation of LDTs for public comment. On January 13, 2017, the FDA released a discussion +38 +paper synthesizing public comments on the 2014 draft guidance documents and outlining a possible approach to regulation of LDTs. The discussion paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies will be adopted with respect to regulating LDTs. +Our subsidiary, DNAG, sells its DNA collection systems to certain laboratories and other customers for use with LDTs. The FDA’s increased regulation of LDTs could make it more difficult for laboratories and other customers to continue offering LDTs that involve genetic or molecular testing. This, in turn, could increase costs, delay the introduction of new LDT’s and reduce demand for DNAG’s products and adversely impact our revenues. +In 2019, the Department of Justice (“DOJ”) indicted a number of telemedicine companies and cancer genetic testing (“CGx”) laboratories for allegedly submitting fraudulent insurance claims to Medicare. A number of these companies were customers of DNAG. As a result of these activities, the FDA has issued letters to genetic testing laboratories indicating that it plans to increase oversight of this market which has caused some of these companies to stop providing testing options or to change how they are reporting the information provided by the testing. The activities have negatively affected this market and there is a risk that these enforcement actions will continue to negatively affect this market by forcing laboratories to either stop offering such services or restricting the use of such services. Such a reduction in testing could result in decreased sales of our DNA collection devices. +Evolving Legislative, Judicial and Ethical Standards on the Use of Technology and Biotechnology Could Affect Our Molecular Collection Systems Business. +The adoption of genetic testing is occurring within the broader context of a myriad of decisions related to genetic patenting and genotyping. Issues associated with regulatory requirements, health insurance, data access and privacy, intellectual property protection, national and international legislative initiatives and other variables impact the widespread adoption of genetic testing or specific segments or tests within the genetic testing market. These developments could impact sales of our molecular collection systems products. +Federal and State Laws Pertaining to Healthcare Fraud and Abuse Could Adversely Affect Our Business, Financial Condition and Results of Operations. +We are subject to various federal and state laws targeting fraud and abuse in the healthcare industry, including anti-kickback laws, false claims laws, laws constraining the sales, marketing and promotion of medical devices by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices, and laws requiring the reporting of certain transactions between manufacturers and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government healthcare programs such as Medicare and Medicaid. Many of the existing requirements have not been definitively interpreted by state authorities or courts, and available guidance is limited. Unless and until we are in full compliance with these laws, we could face enforcement action and fines and other penalties, and could receive adverse publicity, all of which could materially harm our business. In addition, changes in or evolving interpretations of these laws, regulations, or administrative or judicial interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse effect on our business, financial condition and results of operations. +Our International Sales Create Potential Exposure Under Anti-Corruption Laws . +We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the United States Foreign Corrupt Practices Act (the “FCPA”) and similar foreign laws. In 2019, approximately $47.3 million of our consolidated net revenues were generated from sales in a variety of foreign countries. These international activities subject us to the FCPA, the U.K. Bribery Act and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties by business entities for the purpose of obtaining or retaining business. We have operations, enter into agreements with third parties and make sales in countries known to experience corruption. Further international expansion, including the acquisition of foreign entities, may create increased exposure to such practices. Our activities in these countries create the risk of unauthorized payments or offers of payments by one of our employees, consultants, sales agents or distributors that could be in violation of various laws, including the FCPA, even though these parties are not always subject to our control. It is our policy to implement safeguards to discourage these practices by our employees and distributors, including employee training, contracts requiring compliance with the FCPA and similar rules, and standard reviews of our distributors. However, our existing safeguards and any future improvements may not prove to be effective, and our employees, consultants, sales agents or distributors may engage in conduct for which we might be held responsible. Violations of the FCPA and other laws may result in criminal or civil sanctions, which could be severe and we may be subject to other liabilities, which could negatively affect our reputation, business, results of operations and financial condition. +39 +Risks Relating to the Economy, Our Financial Results, Investments, Credit Facilities and Need for Financing +Economic Volatility and Disruption Could Adversely Affect Our Results of Operations, Cash Flow and Financial Condition or Those of Our Customers and Suppliers. +Volatile economic conditions may occur again or continue in the future. These conditions could adversely affect our financial performance and condition or those of our customers and suppliers. These circumstances could also adversely affect our access to liquidity needed to conduct or expand our business or conduct future acquisitions or make other discretionary investments. Many of our customers rely on public funding provided by federal, state and local governments, and this funding has been and may continue to be reduced or deferred as a result of economic conditions or other factors. These circumstances may adversely impact our customers and suppliers, which, in turn, could adversely affect their ability to purchase and/or distribute our products or supply us with necessary equipment, raw materials or components. Even with the improvement of economic conditions, it may take time for our customers and suppliers to establish new budgets and return to normal purchasing and shipping patterns. We cannot predict the reoccurrence of any economic slowdown or the strength or sustainability of an economic recovery. +An Impairment of Goodwill and Intangible Assets Could Reduce our Earnings . +At December 31, 2019, our consolidated balance sheet reflected approximately $36.2 million of goodwill and approximately $14.7 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. U.S. generally accepted accounting principles (“U.S. GAAP”) require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, such as intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The impairment review often cannot be done at the level of the individual asset and it must instead be applied to a group of assets. For the purpose of our annual goodwill impairment testing based on the current circumstances of how we manage or business, this group of assets is the Company as a whole. If we determine that any of our goodwill or intangible assets were impaired, we will be required to take an immediate charge to earnings and our results of operations could be adversely affected. +We Have Experienced Losses in the Past and May Not Be Able To Maintain Profitable Operations . +We experienced annual net losses during the five years prior to 2015. In addition, as of December 31, 2019, the Company had an accumulated deficit of $82.5 million. Even though we achieved profitability since 2015, there can be no assurance that we will be able to sustain his profitability in the future. +Our ability to continue profitable operations in the future will be dependent upon a number of factors including, without limitation, the following: +• +Our ability to continue growing sales of our molecular collection products and related genomic and microbiome laboratory services; +• +Our ability to mitigate declining sales of our OraQuick ADVANCE ® HIV 1/2 test in the United States and expand sales of our OraQuick ® HIV Self-Test internationally; +• +Changes in customer buying patterns or a buildup of significant quantities in our distributors’ inventories or distribution channels; and +• +The level of expenditures we are required to make in order to develop, obtain regulatory approvals for and successfully commercialize our new products; +• +Our ability to expand our business through the acquisition of other companies or technologies or through internal development of new or improved products; +• +Our ability to improve manufacturing efficiencies; +• +Our ability to successfully launch new products after receipt of required regulatory approvals or the acquisition of rights to those products; +• +The degree to which our major distributors and customers comply with their contractual obligations, including minimum purchase commitments; +• +Whether we are successful in obtaining and maintaining required regulatory approvals and registrations for our new products; +• +The level of competition, including the degree to which competitors sell lower priced products or more attractive offerings to compete with our products; +• +Changes in economic conditions in domestic or international markets, such as economic downturns, reduced demand, inflation and currency fluctuations; +40 +• +Failure to achieve our revenue growth targets; +• +The costs and results of patent infringement, product liability and other litigation or claims asserted by or against us. +We May Experience Fluctuations in Our Financial Results or Fail to Meet Our Financial Projections. +Our operating results can fluctuate from quarter to quarter and year to year, which could cause our growth or financial performance to fall below the expectations of investors and securities analysts. Our financial projections for future periods are based on a number of assumptions, including estimated demand for our products. However, sales to our distributors and other customers may fall short of expectations because of lower than estimated demand or other factors, including continued volatility and disruption in economic conditions, increasing competition, seasonal fluctuations, changes in ordering patterns or business strategy, reduced governmental funding and other circumstances described elsewhere in this Annual Report. Infrequent, unusual or unexpected changes in revenues or costs could also contribute to the variability of our financial results. +Customers in certain of the markets we serve often submit a high percentage of purchase orders in the third month of a calendar quarter. Although this can vary from quarter to quarter, many customers make purchase decisions late in a quarter due to budgetary or financial requirements. In addition, certain governmental customers must fully spend budgeted funds by the end of their fiscal year or risk losing these funds, which can contribute to fluctuations in our sales from year-to-year. This can make it difficult to accurately forecast whether we will achieve our quarterly sales forecasts and can cause variability in our operating results. +In addition, our products provide different contributions to our gross margin. Accordingly, our operating results could also fluctuate and be affected by the mix of products sold and the relative prices and gross margin contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely affect our reputation and the price of our Common Stock. +Changes in Foreign Currency Exchange Rates Could Negatively Affect Our Operating Results. +Our financial statements are stated in U.S. Dollars and, historically, most of our international sales have also been denominated in U.S. Dollars. As a result, in the past our exposure to foreign currency exchange rate risk has not been material. Nonetheless, these sales are subject to currency risks, since changes in the values of foreign currencies relative to the value of the U.S. dollar can render our products comparatively more expensive. These exchange rate fluctuations could negatively impact international sales of our products, as could changes in the general economic conditions in those markets. +In addition, the revenues and expenses of our subsidiary, DNAG, are recorded in Canadian Dollars and the revenues and expenses of our subsidiary Novosanis are recorded in Euros. Revenues and expenses denominated in foreign currencies are translated into U.S. dollars for purposes of reporting our consolidated financial results. Our expectation is that the businesses of our foreign subsidiaries will continue to grow and our exposure to foreign currency exchange rates may be more significant than in past years. +Exchange rate fluctuations may affect the revenues and expenses of our foreign subsidiaries and the translation of those financial results into U.S. dollars. Favorable movement in exchange rates have benefited us in prior periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements including our balance sheet, revenues and results of operations, could be negatively affected. In addition, fluctuations in exchange rates could affect year-to-year comparability of operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future. However, our attempts to hedge against these risks may not be successful. If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. +Tax Matters, Including the Changes in Corporate Tax Rates, Disagreements with Taxing Authorities and Imposition of New Taxes Could Impact our Results of Operations and Financial Condition. +We are subject to income and other taxes in the U.S. and our operations, plans and results are affected by tax and other initiatives. On December 22, 2017, the U.S. Government enacted comprehensive tax legislation known as the Tax Cuts and Jobs Act (the “Tax Act”). This legislation made broad and complex changes to the U.S. tax code, including but not limited to a reduction in the corporate tax rate from 35% to 21%, a one-time transition tax on certain unrepatriated earnings of foreign subsidiaries and a first year acceleration of expensing of certain capital expenditures. The Tax Act also introduced new tax laws that may impact our taxable income, which include, but not be limited to, a new provision designed to tax global intangible low taxed income (“GILTI”), limitations on the deductibility of certain executive compensation, creating a base erosion anti-abuse tax (“BEAT”) and modifying or repealing many deductions and credits. Changes in the political makeup of the U.S. Congress could also result in the reversal of some or all of the effects of the Tax Act. +41 +We are also subject to regular reviews, examinations, and audits by the Internal Revenue Service and other taxing authorities with respect to our taxes. Although we believe our tax estimates are reasonable, if a taxing authority disagrees with the positions we have taken, we could face additional tax liability, including interest and penalties. There can be no assurance that payment of such additional amounts upon final adjudication of any disputes will not have a material impact on our results of operations and financial position. +We also need to comply with new, evolving or revised tax laws and regulations. The enactment of new or revised foreign or domestic tax regulations or increases in tariffs or changes in the application or interpretation of the Tax Act, could have an adverse effect on our business or on our results of operations. +We May Require Future Additional Capital. +Our future liquidity and ability to meet our future capital requirements will depend on numerous factors, including, but not limited to, the following: +• +The costs, scope and timing of strategic acquisitions; +• +The costs and timing of expansion of sales and marketing activities; +• +The timing and success of the commercial launch of new products or services; +• +The extent to which we gain or expand market acceptance for existing, new or enhanced products and services; +• +The costs and timing of the expansion of our manufacturing and laboratory capacity; +• +The success of our research and product development efforts; +• +The time, cost and degree of success of conducting clinical trials and obtaining regulatory approvals; +• +The magnitude of capital expenditures; +• +Changes in existing and potential relationships with distributors and other business partners; +• +The costs involved in obtaining and enforcing patents, proprietary rights and necessary licenses; +• +The costs and liability associated with patent infringement or other types of litigation; and +• +Competing technological and market developments. +If additional financing is needed, we may seek to raise funds through the sale of equity or other securities or through bank borrowings. There can be no assurance that financing through the sale of securities, bank borrowings or otherwise will be available to us on satisfactory terms, or at all. +Terrorist Attacks, Natural Disasters or Other Catastrophic Events May Adversely Affect Our Business. +Terrorist attacks, natural disasters or other catastrophic events, including pandemics, and subsequent governmental responses to these events, could cause economic instability. These actions could adversely affect economic conditions both within and outside the United States and reduce demand for our products. These events could disrupt the operations of our customers and suppliers and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to provide raw materials and finished products. +Although we have business interruption insurance, our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace and could require substantial replacement lead-time. Various types of disasters, including earthquakes, fires, floods, acts of terrorism and pandemics, may affect our manufacturing facilities and computer systems. In the event our existing manufacturing facilities or computer systems are affected by man-made or natural disasters, including pandemics, we may have difficulty operating our business and may be unable to manufacture products for sale or meet customer demands or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business. Moreover, we may incur incremental costs following an unforeseen event which could adversely affect our results of operation. +42 +Risks Relating to Our Common Stock +Our Stock Price Could Continue to be Volatile. +Our stock price has been volatile, has fluctuated substantially in the past, may be volatile in the future and could experience substantial declines. The following factors, among others, could have a significant impact on the market for our Common Stock: +• +The performance of our business, including our efforts to increase sales of our OraQuick® HIV, HCV and molecular collection systems products and our OraQuick® In-Home HIV test and HIV Self-Test; +• +Our efforts to expand sales of our genomic and microbiome laboratory service offerings; +• +Future announcements concerning us and our products or services, including with respect to significant acquisitions, strategic collaborations and joint ventures; +• +Ability to achieve the expected benefits, enhanced revenue growth and synergies from strategic acquisitions; +• +Clinical results with respect to our products or services or those of our competitors; +• +The status of clinical studies and pending submissions for required regulatory approvals; +• +The announcement of regulatory or enforcement actions by the FDA or other agencies against us, our products or services, or one or more of our customers; +• +The gain or loss of significant contracts and availability of funding for the purchase of our products and services; +• +Delays in the development, regulatory approval or commercialization of new or enhanced products or services; +• +Legislative developments and industry or competitive trends; +• +Biological or medical discoveries; +• +Disputes or developments with key customers, distributors or suppliers; +• +Developments in patent or other proprietary rights; +• +Litigation or threatened litigation; +• +Complaints or concerns about the performance or safety of our products and publicity about those issues, including publicity expressed through social media or otherwise over the internet; +• +Failure to achieve, or changes in, financial estimates by securities analysts and comments or opinions about us by securities analysts or major stockholders; +• +Governmental regulation; +• +Changes in the level of competition; +• +Loss of or declines in sales to major distributors or customers or changes in the mix of products sold; +• +Period-to-period fluctuations in our operating results; +• +Additions or departures of key personnel; +• +General market and economic conditions; and +• +Terrorist attacks, civil unrest, war and national disasters, including pandemics. +In addition, the stock market in general has experienced extreme price and volume fluctuations that have affected the market price of our Common Stock, as well as the stock of many companies in the diagnostics and life sciences industries. Often, price fluctuations are unrelated to the operating performance of the specific companies whose stock is affected. +In the past, following periods of volatility in the market price of a company’s stock, securities class action litigation has occurred against the issuing company. If we were subject to this type of litigation in the future, we could incur substantial costs and experience a subsequent diversion of our management’s attention and resources, each of which could have a material adverse effect on our revenue and earnings. Any adverse determination in this type of litigation could also subject us to significant liabilities. +43 +Future Sales of Our Common Stock by Existing Stockholders, Executive Officers or Directors Could Depress the Market Price of Our Common Stock and Make It More Difficult For Us to Sell Stock in the Future. +Sales of our Common Stock in the public market, or the perception that such sales may occur, could negatively impact the market price of our Common Stock. We are unable to estimate the number of shares of our Common Stock that may actually be resold in the public market since this will depend on the market price for our Common Stock, the individual circumstances of the sellers and other factors. +We have a number of institutional stockholders that own significant blocks of our Common Stock. If one or more of these stockholders sell large portions of their holdings in a relatively short time, for liquidity or other reasons, the prevailing market price of our Common Stock could be negatively affected. In addition, it is possible that one or more of our executive officers or non-employee members of our Board of Directors could sell shares of our Common Stock during an open trading window or pursuant to a 10b5-1 sales plan under our Insider Trading Policy. These transactions and the perceived reasons for these transactions could have a negative effect on the prevailing market price of our Common Stock. +Investor Confidence and Share Value May be Adversely Impacted if We and/or Our Independent Registered Public Accounting Firm Conclude That Our Internal Control Over Financial Reporting is Not Effective. +As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring us, as a public company, to include a report in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal control over financial reporting. In addition, our independent registered public accounting firm must report on the effectiveness of these internal controls. +We expect that our internal controls will continue to evolve as our business activities change. Although we seek to diligently and vigorously review our internal control over financial reporting in an effort to ensure compliance with the Section 404 requirements, any control system, regardless of how well designed, operated and evaluated, can provide only reasonable, not absolute, assurance that its objectives will be met. In addition, the overall quality of our internal controls may be affected by the internal control over financial reporting implemented by any business we acquire and our ability to assess and successfully integrate the internal controls of any such business. +If, during any year, our independent registered public accounting firm is not satisfied with our internal control over financial reporting or the level at which our controls are documented, designed, operated, tested or assessed, or if the independent registered public accounting firm interprets the requirements, rules or regulations differently than we do, then it may issue a report that is qualified. We also could conclude that our internal control over financial reporting is not effective. These events could result in an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements and effectiveness of our internal controls, which ultimately could negatively impact the market price of our Common Stock. +Our Business Could Be Negatively Impacted as a Result of Stockholder Activism or an Unsolicited Takeover Proposal or a Proxy Contest . +In recent years, proxy contests and other forms of stockholder activism have been directed against numerous public companies. If a proxy contest or an unsolicited takeover proposal is made with respect to us, we could incur significant costs in defending our Company, which would have an adverse effect on our financial results. Stockholder activists may also seek to involve themselves in the governance, strategic direction and operations of our Company. Such proposals may disrupt our business and divert the attention of our management and employees, and any perceived uncertainties as to our future direction resulting from such a situation could result in the loss of potential business opportunities, be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel and business partners, all of which could adversely affect our business. In addition, actions of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business. +Because We Do Not Intend to Pay Cash Dividends on Our Common Stock, an Investor in Our Common Stock Will Benefit Only if Our Stock Appreciates in Value. +We currently intend to retain our current earnings and future earnings, if any, to finance the expansion of our business and do not expect to pay any cash dividends on our Common Stock in the foreseeable future. As a result, the success of an investment in our Common Stock will depend entirely upon any future appreciation. There is no guarantee that our Common Stock will appreciate in value or even maintain the price at which investors purchased their shares. +44 +Certain Provisions in Our Certificate of Incorporation and Bylaws and Under Delaware Law Could Make a Third-Party Acquisition of Us Difficult. +Our Certificate of Incorporation and Bylaws contain provisions that could make it more difficult for a third party to acquire us, even if doing so would be beneficial to our stockholders. We are also subject to certain provisions of Delaware law that could delay, deter or prevent a change in control of us. These provisions could limit the price investors might be willing to pay in the future for shares of our Common Stock. +Future Sales of Shares of Our Common Stock Could Adversely Affect the Trading Price of Our Common Stock and Our Ability to Raise Funds in New Equity Offerings. +Future sales of a substantial number of our shares of Common Stock or equity-related securities in the public market or privately, or the perception that such sales may occur, could adversely affect prevailing trading prices of our Common Stock, and could impair our ability to raise capital through future offerings of equity or equity-related securities. No prediction can be made as to the effect, if any, that future sales of shares of Common Stock or the availability of shares of Common Stock for future sale will have on the trading price of our Common Stock. +ITEM 1B. +Unresolved Staff Comments. +Not Applicable. +ITEM 2. +Properties. +We own a 48,000 square foot facility which is OraSure’s primary corporate office and manufacturing facility, a 31,700 square foot facility that houses our sales and marketing, research and development, human resources, and regulatory and quality offices, and a 33,500 square foot facility which is used for manufacturing activities. Each of these facilities is located in Bethlehem, Pennsylvania. We also rent additional warehouse space on an as-needed basis, including a 70,000 square foot warehouse in Bethlehem Township, Northampton County, Pennsylvania. In addition, our subsidiary, DNAG, leases a 35,883 square foot facility in Ottawa, Canada, which is used as its primary corporate office and houses sales and marketing, manufacturing, distribution, research and development, and regulatory and quality operations. Our other subsidiaries, CoreBiome, Diversigen and Novosanis, also lease facilities for their operations. +We believe that the facilities described above are adequate for our current requirements. +ITEM 3. +Legal Proceedings. +From time to time, we are involved in certain legal actions arising in the ordinary course of business. In management’s opinion, the outcomes of such actions, either individually or in the aggregate, are not expected to have a material adverse effect on our future financial position or results of operations. +On February 6, 2017, DNAG entered into a settlement and license agreement (the “Settlement Agreement”) in order to settle certain patent infringement and breach of contract litigation against Ancestry.comDNA, LLC (“Ancestry”) and its contract manufacturer. This litigation was related to a saliva DNA collection device sold by Ancestry that was similar to products sold by DNAG. Under the terms of the Settlement Agreement, DNAG and Ancestry agreed to certain procedures for considering whether future versions of Ancestry’s saliva DNA collection product are covered by the DNAG patents licensed to Ancestry (the “Licensed Patents”) and thus subject to ongoing royalties under the Settlement Agreement. We have been in a dispute with Ancestry regarding whether yet-to-be launched Ancestry products are covered by the Licensed Patents. In March 2019, Ancestry filed a Dispute Notice and Request for Arbitration (the “Notice”) with an alternative dispute resolution services provider in order to initiate a binding arbitration proceeding pursuant to the Settlement Agreement. DNAG denied the allegations contained in the Notice and asserted that the potential new Ancestry products are covered by the Licensed Patents and would be subject to ongoing royalties if such products are commercialized by Ancestry. A panel of arbitrators was appointed (the “Panel”) and this arbitration proceeding was completed in January 2020. In February 2020, the Panel issued a decision that found that the potential new Ancestry products do not infringe the DNAG patents asserted in the arbitration. As a result, these new Ancestry products will not be subject to the royalties under the Settlement Agreement. Under the terms of the Settlement Agreement, the Panel’s decision is final and binding on the parties. +ITEM 4. +Mine Safety Disclosures. +Not Applicable. +45 +PART II +ITEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +Market Information +Our Common Stock is listed for trading on the Global Select Market tier of The Nasdaq Stock Market LLC (“NASDAQ”) under the symbol “OSUR”. On February 21, 2020, there were 357 holders of record and approximately 15,402 holders in street name of our Common Stock, and the closing price of our Common Stock was $6.09 per share. +Dividends +We have never paid any cash dividends and our Board of Directors does not anticipate paying cash dividends in the foreseeable future. We intend to retain any future earnings to provide funds for the operation and expansion of our business. +Share Repurchases and Retirements +Period +Total number of shares purchased +Average price paid per Share +Total number of shares purchased as part of publicly announced plans or programs +Maximum number (or approximate dollar value) of shares that may yet be repurchased under the plans or programs (1, 2) +October 1, 2019- October 31, 2019 +— +— +— +$ +11,984,720 +November 1, 2019 - November 30, 2019 +— +— +— +$ +11,984,720 +December 1, 2019 - December 31, 2019 +— +— +— +$ +11,984,720 +— +— +(1) +On August 5, 2008, our Board of Directors approved a share repurchase program pursuant to which we are permitted to acquire up to $25.0 million of outstanding shares. This share repurchase program may be discontinued at any time. +(2) +This column represents the amount that remains available under the $25.0 million repurchase plan, as of the period indicated. We have made no commitment to purchase any shares under this plan. +Performance Graph +The performance graph set forth below shall not be deemed “soliciting material” or “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to liability under that Section. This graph will not be deemed “incorporated by reference” into any filing under the Securities Act of 1933, as amended, or the Exchange Act, whether such filing occurs before or after the date hereof, regardless of any general incorporation language in such filing . +The following graph compares the cumulative total returns to investors in the Company’s Common Stock, the NASDAQ Composite Index and the NASDAQ Biotechnology Index for the period from December 31, 2014 through December 31, 2019. The graph assumes that $100 was invested on December 31, 2014 in the Company’s Common Stock and in each of the above-mentioned indices, and that all dividends, if any, were reinvested. +46 +The NASDAQ Composite Index was chosen because it is a broad index of companies whose equity securities are traded on NASDAQ. The NASDAQ Biotechnology Index was chosen because it includes a number of our competitors. Stockholders are cautioned that the graph shows the returns to investors only as of the dates noted and may not be representative of the returns for any other past or future period. +* +$100 invested on 12/31/14 in stock or index, including reinvestment of dividends. +Fiscal year ending December 31, +2014 +2015 +2016 +2017 +2018 +2019 +OraSure Technologies, Inc. +100.00 +63.51 +86.59 +186.00 +115.19 +79.19 +NASDAQ Composite +100.00 +106.96 +116.45 +150.96 +146.67 +200.49 +NASDAQ Biotechnology +100.00 +111.77 +87.91 +106.92 +97.45 +121.92 +Securities Authorized for Issuance Under Equity Compensation Plans +For certain information concerning securities authorized for issuance under our equity compensation plan, see Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” +47 +ITEM 6. +Selected Consoli dated Financial Data. +The following table sets forth selected consolidated financial data of the Company. This information should be read in conjunction with the consolidated financial statements and notes thereto included in Item 15 and the information set forth in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” +Selected Consolidated Financial Data +(In thousands, except per share data) +Years ended December 31, +2019 +2018 +2017 +2016 +2015 +Operating Results: +Net revenues +$ +154,605 +$ +181,743 +$ +167,064 +$ +128,198 +(4) +$ +119,719 +Costs and expenses +135,994 +(1) +153,314 +(2) +126,826 +(3) +107,933 +111,661 +Operating income +18,611 +28,429 +40,238 +20,265 +8,058 +Other income, net +2,720 +3,287 +794 +58 +774 +Income tax expense +4,675 +11,320 +10,084 +603 +665 +Net income +16,656 +20,396 +30,948 +19,720 +8,167 +Earnings per share +Basic +$ +0.27 +$ +0.33 +$ +0.52 +$ +0.35 +$ +0.14 +Diluted +$ +0.27 +$ +0.33 +$ +0.51 +$ +0.35 +$ +0.14 +Shares used in computing earnings per share +Basic +61,675 +61,112 +59,050 +55,615 +56,397 +Diluted +62,170 +62,532 +61,024 +56,513 +56,846 +Cash Flow: +Cash flows provided by operating activities +$ +9,804 +(1) +$ +39,090 +$ +28,156 +(3) +$ +24,598 +$ +15,773 +December 31, +2019 +2018 +2017 +2016 +2015 +Financial Position: +Cash, cash equivalents, and investments +$ +189,758 +$ +201,324 +$ +176,587 +$ +120,950 +$ +101,319 +Working capital +191,837 +191,332 +189,668 +139,106 +111,480 +Total assets +349,295 +315,571 +296,201 +207,935 +189,321 +Accumulated deficit +(82,533 +) +(99,189 +) +(119,510 +) +(150,458 +) +(170,178 +) +Stockholders' equity +307,145 +283,378 +258,081 +185,850 +159,436 +(1) +Includes a pre-tax gain on sale of our cryosurgical business of $10.1 million and $664,000 of non-cash pre-tax income associated with the change in the fair value of acquisition-related contingent consideration, both of which was recorded as a reduction of operating expenses in the indicated period and $1.8 million of transaction costs associated with our acquisitions of CoreBiome, Novosanis and Diversigen. +(2) +Includes $9.6 million of transition costs associated with our change in management and $1.2 million of transaction costs associated with our acquisitions of CoreBiome and Novosanis. +( 3 ) +Includes a $12.5 million gain associated with the settlement of our litigation with Ancestry.com DNA LLC and its contract manufacturer, which was recorded as a reduction of operating expenses in the indicated period. +( 4 ) +Includes an additional $5.4 million of exclusivity payments recognized in other revenues as a result of the early termination of our HCV co-promotion agreement with AbbVie, bringing total exclusivity payments recognized in 2016 to $18.9 million. +48 +ITEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +Statements below regarding future events or performance are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Our actual results could be quite different from those expressed or implied by the forward-looking statements. Factors that could affect results are discussed more fully under the Item 1A, entitled “Risk Factors,” and elsewhere in this Annual Report. Although forward-looking statements help to provide complete information about us, readers should keep in mind that forward-looking statements may not be reliable. Readers are cautioned not to place undue reliance on the forward-looking statements. We undertake no duty to update any forward-looking statements made herein after the date of this Annual Report. +The following discussion should be read in conjunction with the consolidated financial statements contained herein and the notes thereto, along with the Section entitled “Critical Accounting Policies and Estimates,” set forth below. +Overview and Business Segments +Our business consists of two segments: our “OSUR” business consists of the development, manufacture, marketing and sale of oral fluid diagnostic products and specimen collection devices using our proprietary technologies, other diagnostic products including immunoassays and other in vitro diagnostic tests that are used on other specimen types. Our molecular products and services or “DNAG” business consists of the manufacture and sale of kits that are used to collect, stabilize, transport and store biological samples of genetic material for molecular testing. Our collection kits are also used for the collection of first-void urine for liquid biopsy in the prostate and bladder cancer markets; and in the sexually transmitted infection screening market. In addition, our DNAG business provides microbiome laboratory and bioinformatics services. The DNAG segment also includes genomic and microbiome laboratory testing and analytical services. +Our OSUR diagnostic products include tests for diseases including HIV and Hepatitis C that are performed on a rapid basis at the point of care and tests that are processed in a laboratory. These products are sold in the United States and internationally to various clinical laboratories, hospitals, clinics, and other public health organizations, distributors, government agencies, physicians’ offices, and commercial and industrial entities. Our HIV product is also sold in a consumer-friendly format in the OTC and public health markets in the U.S. and as a self-test to individuals in a number of other countries. We also previously manufactured and sold medical devices used for the removal of benign skin lesions by cryosurgery or freezing. These cryosurgical products were sold in both professional and OTC markets in North America, Europe, Central and South America, and Australia. We sold the assets associated with our cryosurgical systems business to a third party in August 2019. +Our DNAG or molecular products and services systems business is operated by our subsidiaries, DNAG, CoreBiome, Novosanis and Diversigen. DNAG’s specimen collection devices provide all-in-one systems for the collection, stabilization, transportation and storage of nucleic acids from human saliva and other biological sample types for genetic and microbiome applications. Our products are used for academic research and commercial applications, including ancestry, disease risk management, lifestyle and animal testing. Included in the disease risk management area are pharmacogenomics testing, hereditary disease screening, prenatal or cancer screening, population health initiatives and other molecular testing in DNA or RNA for the diagnosis of acute disease. CoreBiome and Diversigen provide the laboratory testing and bioinformatics services. Novosanis’ Colli-Pee collection device is designed for the volumetric collection of first-void urine for use in research, screening and diagnostics for the liquid biopsy and sexually transmitted infection markets. We also sell research use only sample collection products into the microbiome market and we offer our customers a suite of genomics and microbiome services, which range from package customization and study design optimization to extraction, analysis and reporting services. We serve customers worldwide in the research, healthcare, pharmaceutical and agricultural communities . +Recent Developments +Business Acquisitions +In early January 2019, we acquired two privately-held, early-stage companies, CoreBiome and Novosanis, in order to add differentiated products and services to the molecular collection systems segment of our business. +CoreBiome, a spin-off from the University of Minnesota, is based in St. Paul, Minnesota and provides microbiome laboratory and analytical services that can accelerate research and discovery for customers in the pharmaceutical, agricultural and academic research communities. CoreBiome was co-founded in 2016 by Dr. Dan Knights, a globally-recognized expert in microbiome informatics who has developed leading methods for analyzing microbiome data, along with Dr. Daryl Gohl and Dr. Kenny Beckman, domain experts in genomics methods and clinical lab operations. +49 +Novosanis is a Belgian company that was founded in 2013 as a spin-off from the University of Antwerp, Belgium. Novosanis is an early commercial stage producer and distributor of urine sample collection devices targeting the liquid biopsy and sexually transmitted infection screening markets. Novosanis’ primary product is Colli-Pee, an easy to use device designed for the standardized collection of first-void urine which can be used in the privacy of the user’s home or in a clinic. Product validation and clinical trials are also under way with various sexually transmitted infection test manufacturers. +In November 2019, we acquired another microbiome laboratory services provider, Diversigen. Based in Houston, Texas, Diversigen provides science-driven, customized solutions for metagenomics sequencing, bioinformatics, and statistical analysis for the study of the microbiome. The company was founded in 2013 by Dr. Joseph Petrosino, director of the Alkek Center for Metagenomics and Microbiome Research at the Baylor College of Medicine (“BCM”), where Diversigen was a BCM portfolio company. Diversigen was the first company to establish microbiome protocols in accordance with CAP accreditation and CLIA guidelines. +We used cash of $23.8 million in the aggregate to pay for the acquisition of these three companies. Through December 31, 2019, we have incurred a total of $1.8 million of acquisition related costs, including investment banking fees and accounting, legal and other professional fees, related to the acquisitions, all of which were expensed and reported as a component of general and administrative expenses in the consolidated statement of income for the year ended December 31, 2019. +Sale of Business Line +In August 2019, we sold all rights and title to the assets necessary to operate our cryosurgical systems line of business to a third party for $12.0 million. We also entered into a transition services agreement with this party in which both parties agreed to provide certain transition services beginning after the closing. This line of business consisted of medical devices used for the removal of benign skin lesions by cryosurgery or freezing. A $10.2 million pre-tax gain on the sale of the business is reflected in our statement of income for the year ended December 31, 2019 and includes the $12.0 million proceeds received net of the fair value of the assets sold, which consisted of inventory and fully-depreciated fixed assets, the legal fees associated with the transaction, and a value attributed to the transition services. +Current Consolidated Financial Results +During the year ended December 31, 2019, our consolidated net revenues decreased 15% to $154.6 million, compared to $181.7 million for the year ended December 31, 2018. Net product and service revenues during the year ended December 31, 2019 decreased 10% when compared to 2018, primarily due to lower sales of our genomics products and lower cryosurgical sales as a result of the divestiture of our cryosurgical systems business in mid-August. Partially offsetting these decreases were higher sales of our microbiome and OraQuick ® HIV and HCV products. Other revenues in 2019 were $6.5 million compared to $16.3 million in 2018. Other revenues in 2019 consisted of royalty income of $5.1 million and other revenues of $1.4 million associated with funded research and development, reimbursement of certain costs under our charitable support agreement with the Bill & Melinda Gates Foundation (“Gates Foundation”), and grant revenue. Other revenues in 2018 consisted of royalty income of $9.7 million and $6.6 million of other revenue associated with funded research and development and cost reimbursement from the Gates Foundation. +Our consolidated net income for the year ended December 31, 2019 was $16.7 million, or $0.27 per share on a fully-diluted basis, compared to consolidated net income of $20.4 million, or $0.33 per share on a fully-diluted basis, for the year ended December 31, 2018. Results for the current year included a pre-tax gain on the sale of our cryosurgical systems business of $10.2 million, $664,000 of non-cash pre-tax income associated with the change in the fair value of acquisition-related contingent consideration and $1.8 million of pre-tax acquisition-related transaction costs associated with the three acquisitions that occurred in 2019. The combined net impact of these items increased earnings per share by approximately $0.14. Results for the year ended December 31, 2018 included $9.6 million of management transition costs associated with the 2018 retirements of our former President and Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) and Chief Operating Officer, and the appointment of their successors. The results for the year ended December 31, 2018 also included $1.2 million of pre-tax acquisition-related transaction costs associated with the acquisitions that were completed in January 2019. The combined impact of these charges decreased earnings per share by approximately $0.18. +Cash provided by operating activities for the year ended December 31, 2019 was $9.8 million. Cash provided by operating activities during the year ended December 31, 2018 was $39.1 million. As of December 31, 2019, we had $189.8 million in cash, cash equivalents, and available-for-sale securities, compared to $201.3 million at December 31, 2018. +50 +Results of Operations +YEAR ENDED DECEMBER 31, 2019 COMPARED TO DECEMBER 31, 2018 +CONSOLIDATED NET REVENUES +The table below shows a breakdown of total net revenues (dollars in thousands) generated by each of our business segments. +Years Ended December 31, +Dollars +Percentage of Total Net Revenues +2019 +2018 +% Change +2019 +2018 +OSUR +$ +77,259 +$ +78,973 +(2 +) +% +50 +% +43 +% +DNAG +70,814 +86,455 +(18 +) +46 +48 +Net product and service revenues +148,073 +165,428 +(10 +) +96 +91 +Other +6,532 +16,315 +(60 +) +4 +9 +Net revenues +$ +154,605 +$ +181,743 +(15 +) +% +100 +% +100 +% +Consolidated net product and service revenues decreased 10% to $148.1 million in 2019 from $165.4 million in 2018. Lower sales of our genomics and cryosurgical systems products were partially offset by higher microbiome product and service revenues and by higher OraQuick ® HIV and HCV product revenues. Other revenues in 2019 consisted of $5.1 million in royalty income and $1.4 million associated with funded research and development, grants, and reimbursement of certain costs under our charitable support agreement with the Gates Foundation . Other revenues in 2018 consisted of royalty income of $9.7 million and $6.6 million of other revenue associated with funded research and development and cost reimbursement from the Gates Foundation. +Consolidated net revenues from products sold to customers outside of the United States were $47.3 million and $44.9 million, or 31% and 25% of total net revenues, during the years ended December 31, 2019 and 2018, respectively. Because the majority of our international sales are denominated in U.S. dollars, the impact of fluctuating foreign currency exchange rates was not material to our total consolidated net revenues. +Net Revenues by Segment +OSUR Segment +The table below shows the amount of total net revenues (dollars in thousands) generated by our OSUR segment. +Years Ended December 31, +Dollars +Percentage of Total Net Revenues +Market +2019 +2018 +% Change +2019 +2018 +Infectious disease testing +$ +58,016 +$ +56,148 +3 +% +74 +% +65 +% +Risk assessment testing +12,189 +12,058 +1 +16 +14 +Cryosurgical systems +7,054 +10,767 +(34 +) +9 +13 +Net product revenues +77,259 +78,973 +(2 +) +99 +92 +Other +966 +6,662 +(85 +) +1 +8 +Net revenues +$ +78,225 +$ +85,635 +(9 +) +% +100 +% +100 +% +Infectious Disease Testing Market +Sales to the infectious disease testing market increased 3% to $58.0 million in 2019 from $56.1 million in 2018. This increase resulted from higher international sales of our OraQuick ® HIV Self-Test and higher domestic sales of our OraQuick ® HCV product, partially offset by lower domestic sales of our OraQuick ® HIV professional product and our OraQuick ® In-Home test. +51 +The table below shows a breakdown of our total net OraQuick ® HIV and HCV product revenues (dollars in thousands) during 201 9 and 201 8 . +Years Ended December 31, +Market +2019 +2018 +% Change +Domestic HIV +$ +17,984 +$ +19,663 +(9 +) +% +International HIV +25,108 +21,794 +15 +Net HIV revenues +43,092 +41,457 +4 +Domestic HCV +8,108 +7,490 +8 +International HCV +4,864 +4,904 +(1 +) +Net HCV revenues +12,972 +12,394 +5 +Net OraQuick® revenues +$ +56,064 +$ +53,851 +4 +% +Domestic OraQuick ® HIV sales decreased 9% to $18.0 million for the year ended December 31, 2019 from $19.7 million for the year ended December 31, 2018. This decrease was primarily the result of reduced sales of our professional product due to price competition and competition from fourth generation automated HIV immunoassays performed in a laboratory and lower sales of our OTC product. +International sales of our OraQuick ® HIV products during 2019 increased 15% to $25.1 million from $21.8 million in 2018. This increase was largely due higher sales of our OraQuick ® Self-Test in Africa as well as increased sales of our professional product in Asia. Product revenues in 2019 and 2018 included approximately $3.3 million and $4.4 million, respectively, of support payments under the charitable support agreement with the Gates Foundation. +Domestic OraQuick ® HCV sales increased 8% to $8.1 million in 2019 from $7.5 million in 2018 primarily due to increased demand driven by the domestic opioid crisis. International OraQuick ® HCV sales remained consistent at $4.9 million in 2019 and 2018. +Risk Assessment Market +Sales to the risk assessment market increased 1% to $12.2 million for the year ended December 31, 2019 from $12.1 million for the year ended December 31, 2018. +Cryosurgical Systems Market +Sales of our cryosurgical systems products decreased 34% to $7.1 million in 2019 from $10.8 million in 2018 due to the sale of this business in August 2019. +Other revenues +Other revenues in 2019 decreased 85% to $966,000 from $6.7 million in 2018. Revenue associated with funding of our research and development efforts decreased to $706,000 in 2019 compared to $5.0 million in 2018 as a result of the completion of our contract with Biomedical Advanced Research Development Authority (“BARDA”) associated with our Zika product and lower spending on our Ebola product as the project reaches completion. During 2018, because of difficulties in completing development and optimizing our Zika test and because of significant uncertainty regarding the commercial demand for this product, the scope of the work covered by our Zika contract with BARDA was reduced and this project was substantially completed in the first quarter of 2019. Other revenues in 2019 and 2018 also included $261,000 and $1.7 million, respectively, in cost reimbursement under our charitable support agreement with the Gates Foundation, which is separate from the above-referenced support payments from the Gates Foundation that are included in product revenues. +DNAG Segment +Molecular Products and Services +Our products and services revenues decreased 21% to $76.4 million in 2019 from $96.1 million in 2018. +52 +The table below shows a breakdown of our total net molecular product and services revenues (dollars in thousands) during 201 9 and 201 8 . +Years Ended December 31, +Market +2019 +2018 +% Change +Genomics +$ +57,365 +$ +79,765 +(28 +) +% +Microbiome +12,786 +6,690 +91 +Other +663 +— +100 +Net molecular product and services revenues +70,814 +86,455 +(18 +) +Other +5,566 +9,653 +(42 +) +Net molecular product and services revenues +$ +76,380 +$ +96,108 +(21 +) +% +Sales of our genomics products decreased 28% to $57.4 million in 2019 compared to $79.8 million in 2018, largely due to lower customer demand, primarily from a large consumer genomics customer that changed its promotional tactics and resulting purchasing patterns. +Microbiome revenues increased 91% to $12.8 million in 2019 compared to $6.7 million in 2018 due to the inclusion of laboratory service revenues generated by CoreBiome and Diversigen and increased product sales. +Other product revenues represent sales of our Colli-Pee product sold by Novosanis. +Other revenues in 2019 decreased 42% to $5.6 million from $9.7 million largely as a result of lower royalty income partially offset by funded research and development and grant revenues recognized by Novosanis and CoreBiome. Royalty income decreased to $5.1 million in 2019 compared to $9.7 million in 2018. +CONSOLIDATED OPERATING RESULTS +Consolidated gross profit percentage was 61% for the year ended December 31, 2019 compared to 63% for 2018. Gross profit percentage in 2019 was negatively affected by the decline in other revenues which contribute 100% to our gross profit percentage and a less favorable product mix as a result of higher sales of lower gross profit products and services partially offset by lower royalty expense. +Consolidated operating income in 2019 was $18.6 million, a $9.8 million decline from the $28.4 million of operating income reported in 2018. Operating income in 2019 included a pre-tax gain on the sale of our cryosurgical systems business of $10.2 million, $664,000 of non-cash pre-tax income associated with the change in the fair value of acquisition-related contingent consideration, $1.8 million of pre-tax acquisition-related transaction costs, and operating expenses of the Company’s newly acquired subsidiaries. Operating income in 2018 included $9.6 million of transition costs associated with executive management changes and $1.2 million of pre-tax acquisition-related transaction costs. +OPERATING INCOME BY SEGMENT +OSUR Segment +OSUR’s gross profit percentage was 55% in 2019 compared to 56% in 2018. OSUR’s gross profit percentage in 2019 was negatively impacted by an increase in lower profit percentage revenues as a result of the sale of the cryosurgical systems business partially offset by a decrease in royalty expense. +Research and development expenses decreased 4% to $12.2 million in 2019 from $12.7 million in 2018, due to the elimination of spending on our Zika project which was completed in early 2019 and lower spending related to our Ebola product, partially offset by higher costs associated with the development of automated drug testing assays. +Sales and marketing expenses decreased 9% to $18.1 million in 2019 from $19.9 million in 2018, largely due to lower staffing costs. +General and administrative expenses decreased 26% to $22.5 million in 2019 from $30.3 million in 2018 largely due to $9.6 million of transition costs associated with executive management changes in 2018 that did not reoccur in 2019, partially offset by higher professional fees associated with our business development activities . +53 +OSUR’s operating income for 2019 also included a $10.2 million pre-tax gain on the sale of our cryosurgical systems business. I n August 2019, we sold all rights and title to the assets necessary to operate this line of business to CryoConcepts for $12.0 million. The $10.2 million gain includes the $12.0 million proceeds received net of the fair value of the assets sold, which consisted of inventory and fully-depreciated fixed assets, the legal fees associated with the transaction, and a value attributed to the transition services which are being provided by OSUR employees to CryoConcepts for a limited time after closing as agreed to under a transition services agreement. +All of the above contributed to OSUR’s operating income of $154,000 for 2019, which included non-cash charges of $3.0 million for depreciation and amortization and $3.3 million for stock-based compensation. +DNAG Segment +DNAG’s gross profit percentage was 68% in 2019 compared to 69% in 2018. This decrease was attributable to the decline in other revenues which contribute 100% to the gross profit percentage and a less favorable product mix as a result of higher sales of lower gross profit products and services . +Research and development expenses increased 114% to $7.5 million in 2019 from $3.5 million in 2018 due to the inclusion of research and development expense incurred by the newly acquired subsidiaries, higher staffing costs, and higher lab supply and consulting costs in support of bioinformatics and new product initiatives. +Sales and marketing expenses increased 28% to $13.7 million in 2019 compared to $10.7 million in 2018 largely due to an increase in our reserve for uncollectible accounts largely associated with a receivable from a large Chinese genomics customer, and the inclusion of expenses generated by the newly acquired subsidiaries, partially offset by lower staffing costs . +General and administrative expenses increased 60% to $12.8 million in 2019 compared to $8.0 million in 2018, due the inclusion of expenses generated by the Company’s newly acquired subsidiaries and increased staffing, legal and consulting costs . +All of the above contributed to DNAG’s operating income of $18.5 million for 2019, which included non-cash charges of $4.3 million for depreciation and amortization and $777,000 for stock-based compensation. +CONSOLIDATED INCOME TAXES +We continue to believe the full valuation allowance established in 2008 against OSUR’s total U.S. deferred tax asset is appropriate as the facts and circumstances necessitating the allowance have not changed. For the year ended December 31, 2019, we recorded a federal tax benefit of $832,000 and state income tax expense of $892,000 compared to $155,000 of state tax expense recorded in the year ended December 31, 2018. Foreign income tax expense of $4.6 million and $11.2 million was recorded in 2019 and 2018, respectively. The decrease in income tax expense was largely a result of the decrease in income before taxes generated by DNAG and the results generated by Novosanis. +YEAR ENDED DECEMBER 31, 2018 COMPARED TO DECEMBER 31, 2017 +CONSOLIDATED NET REVENUES +The table below shows a breakdown of total net revenues (dollars in thousands) generated by each of our business segments. +Years Ended December 31, +Dollars +Percentage of Total Net Revenues +2018 +2017 +% Change +2018 +2017 +OSUR +$ +78,973 +$ +86,889 +(9 +) +% +43 +% +52 +% +DNAG +86,455 +75,099 +15 +48 +45 +Net product revenues +165,428 +161,988 +2 +91 +97 +Other +16,315 +5,076 +221 +9 +3 +Net revenues +$ +181,743 +$ +167,064 +9 +% +100 +% +100 +% +Consolidated net product revenues increased 2% to $165.4 million in 2018 from $162.0 million in 2017. Higher sales of our molecular collection systems products and higher international sales of our OraQuick ® HIV Self-Test were partially offset by lower sales of our +54 +OraQuick ® HCV products, lower domestic sales of our OraQuick ® HIV products and lower sales of our cryosurgical products. In 2018 w e recorded $9.7 million in royalty income under a litigation settlement agreement. We also recognized $5.0 million as other revenues in connection with funding from BARDA related to our Ebola and Zika products and $1.7 million of cost reimbursement under our charitable support agreement with the Gates Foundation . Other revenues in 2017 included $4.4 million of BARDA funding and $689,000 of cost reimbursement. +Consolidated net revenues from products sold to customers outside of the United States were $44.9 million and $45.6 million, or 25% and 27% of total net revenues, during the years ended December 31, 2018 and 2017, respectively. Because the majority of our international sales are denominated in U.S. dollars, the impact of fluctuating foreign currency exchange rates was not material to our total consolidated net revenues. +Net Revenues by Segment +OSUR Segment +The table below shows the amount of total net revenues (dollars in thousands) generated by our OSUR segment. +Years Ended December 31, +Dollars +Percentage of Total Net Revenues +Market +2018 +2017 +% Change +2018 +2017 +Infectious disease testing +$ +56,148 +$ +61,951 +(9 +) +% +65 +% +67 +% +Risk assessment testing +12,058 +12,659 +(5 +) +14 +14 +Cryosurgical systems +10,767 +12,279 +(12 +) +13 +13 +Net product revenues +78,973 +86,889 +(9 +) +92 +94 +Other +6,662 +5,076 +31 +8 +6 +Net revenues +$ +85,635 +$ +91,965 +(7 +) +% +100 +% +100 +% +Infectious Disease Testing Market +Sales to the infectious disease testing market decreased 9% to $56.1 million in 2018 from $62.0 million in 2017. This decrease resulted from lower domestic and international sales of our OraQuick ® HCV product and lower domestic sales of our OraQuick ® HIV product, partially offset by higher international sales of our OraQuick ® HIV Self-Test. +The table below shows a breakdown of our total net OraQuick ® HIV and HCV product revenues (dollars in thousands) during 2018 and 2017. +Years Ended December 31, +Market +2018 +2017 +% Change +Domestic HIV +$ +19,663 +$ +23,847 +(18 +) +% +International HIV +21,794 +11,301 +93 +Net HIV revenues +41,457 +35,148 +18 +Domestic HCV +7,490 +8,448 +(11 +) +International HCV +4,904 +16,961 +(71 +) +Net HCV revenues +12,394 +25,409 +(51 +) +Net OraQuick® revenues +$ +53,851 +$ +60,557 +(11 +) +% +Domestic OraQuick ® HIV sales decreased 18% to $19.7 million for the year ended December 31, 2018 from $23.8 million for the year ended December 31, 2017. This decrease was primarily the result of competition from point-of-care HIV tests perceived to be more sensitive than our product and competition from fourth generation automated HIV immunoassays performed in a laboratory. +International sales of our OraQuick ® HIV products during 2018 rose 93% to $21.8 million from $11.3 million in 2017. This increase was largely due to the continued shipment of product in support of an HIV self-testing program in Africa, and higher sales of our professional product into certain areas of Europe, Africa, Asia, and Latin America, partially offset by a decline in sales in the Middle East. Funding under the charitable support agreement with the Gates Foundation began in the third quarter of 2017 and product +55 +revenues in 2018 and 2017 included approximately $4.4 million and $1.0 million of support payments under that agreement, respectively. +Domestic OraQuick ® HCV sales decreased 11% to $7.5 million in 2018 from $8.4 million in 2017 primarily due to customer ordering patterns and the non-renewal of, or reductions in, grant funding of HCV testing programs. International OraQuick ® HCV sales decreased 71% to $4.9 million in 2018 from $17.0 million in 2017, due to the non-renewal of a supply contract with a foreign government in support of a countrywide HCV eradication program and the loss of a multi-national humanitarian organization customer that switched to a competitive product due to pricing. +Risk Assessment Market +Sales to the risk assessment market decreased 5% to $12.1 million for the year ended December 31, 2018 from $12.6 million for the year ended December 31, 2017, primarily as a result of a large customer that stopped performing pre-employment drug testing. +Cryosurgical Systems Market +Sales of our cryosurgical systems products decreased 12% to $10.8 million in 2018 from $12.3 million in 2017 due to lower sales of our domestic Histofreezer® product to physicians’ offices due to competitive losses from lower-priced products that entered the market as result of the expiration of the patents associated with our cryosurgical technology and lower sales of our international OTC cryosurgical products. +Other revenues +Other revenues in 2018 increased 31% to $6.7 million from $5.1 million in 2017. Revenue from BARDA funding increased to $5.0 million in 2018 compared to $4.4 million in 2017 as a result of increased work related to our Ebola and Zika products. Other revenues in 2018 also included $1.7 million in reimbursement of certain costs under our charitable support agreement with the Gates Foundation. Reimbursement of these costs began in the third quarter of 2017 and other revenue in 2017 included $689,000 of such cost reimbursement. +DNAG Segment +Molecular Collection Systems +Sales of our molecular collection systems products increased 28% to $96.1 million in 2018 from $75.1 million in 2017. +The table below shows a breakdown of our total net molecular collection systems revenues (dollars in thousands) generated during 2018 and 2017. +Years Ended December 31, +Market +2018 +2017 +% Change +Genomics +$ +79,765 +$ +71,611 +11 +% +Microbiome +6,690 +3,488 +92 +Net molecular collection systems product revenues +86,455 +75,099 +15 +% +Royalty income +9,653 +— +N/A +Net molecular collection systems revenues +$ +96,108 +$ +75,099 +28 +% +Sales of our genomics products rose 11% to $79.8 million in 2018 compared to $71.6 million in 2017, largely as a result of higher customer demand primarily from a large consumer genetics customer, higher sales to academic customers, increased demand of our genomics business in Asia, and higher sales of our ORAcollect ® product. Microbiome sales increased 92% to $6.7 million in 2018 compared to $3.5 million in 2017 as interest in our microbiome product offering continued to grow with both new and existing customers. +We recorded $9.7 million of royalty income in 2018 earned under a litigation settlement agreement. This royalty agreement was entered into in 2017 and required royalty payments beginning in the first quarter of 2018. There were no revenues of this nature in 2017. +56 +C ONSOLIDATED OPERATING RESULTS +Consolidated gross profit percentage was 63% for the year ended December 31, 2018 compared to 59% for 2017. Gross profit percentage in 2018 benefited from improved product mix associated with an increase in higher gross profit percentage sales, lower manufacturing costs associated with our Oragene ® product, increased royalty income and other revenues which have a gross profit percentage of 100%, lower scrap and spoilage costs and lower royalty expense. +Consolidated operating income in 2018 was $28.4 million, an $11.8 million decline from $40.2 million of operating income reported in 2017. Operating income in 2017 included a pre-tax gain of $12.5 million associated with the settlement of our litigation against Ancestry.com DNA LLC and its contract manufacturer. In addition, our results for 2018 were negatively impacted by the inclusion of $9.6 million of transition costs associated with executive management changes, $1.2 million of transaction costs associated with our January 4, 2019 acquisitions, and increased spending on research and development and sales and marketing. +OPERATING INCOME (LOSS) BY SEGMENT +OSUR Segment +OSUR’s gross profit percentage was 56% in 2018 compared to 58% in 2017. OSUR’s gross profit percentage in 2018 was negatively impacted by an increase in lower profit percentage revenues as a result of higher international sales, partially offset by the increase in BARDA funding and cost reimbursement from the Gates Foundation, and lower scrap and spoilage costs and royalty expense. +Research and development expenses increased 21% to $12.7 million in 2018 from $10.5 million in 2017, due to increased spending on our Ebola and Zika products, higher staffing costs, and increased product registration fees related to our expansion in more international markets. +Sales and marketing expenses increased 5% to $19.9 million in 2018 from $18.9 million in 2017, primarily as a result of increased consulting costs associated with our international sales contractors and increased staffing costs associated with higher headcount. +General and administrative expenses increased 35% to $35.3 million in 2018 from $26.1 million in 2017 as a result of the inclusion of $9.6 million of transition costs associated with executive management changes, $1.2 million of transaction costs associated with our recent acquisitions, and higher consulting costs partially offset by a decrease in other staffing related costs. +All of the above contributed to OSUR’s operating loss of $20.1 million for 2018, which included non-cash charges of $3.8 million for depreciation and amortization and $14.7 million for stock-based compensation. +DNAG Segment +DNAG’s gross profit percentage was 69% in 2018 compared to 61% in 2017. This increase was attributable to the royalty income recorded in 2018 and improved product mix associated with an increase in higher gross profit percentage sales and lower manufacturing costs associated with our Oragene ® product. No royalty income was recorded in 2017. +Research and development expenses increased 25% to $3.5 million in 2018 from $2.8 million in 2017 due to higher staffing costs associated with the development of new product and service offerings. +Sales and marketing expenses increased 12% to $10.7 million in 2018 compared to $9.6 million in 2017 due to higher staffing and commission expenses. +General and administrative expenses decreased 4% to $3.1 million in 2018 compared to $3.2 million in 2017, due to lower legal costs. +Operating expenses in 2017 were offset by the $12.5 million pre-tax gain associated with the settlement of the Ancestry litigation. +All of the above contributed to DNAG’s operating income of $48.6 million for 2018, which included non-cash charges of $3.4 million for depreciation and amortization and $540,000 for stock-based compensation. +CONSOLIDATED INCOME TAXES +57 +We continue to believe the full valuation allowance established in 2008 against OSUR’s total U.S. deferred tax asset is appropriate as the facts and circumstances necessitating the allowance have not changed. For the year ended December 31, 2018, we recorded state income tax expense of $155,000 compared to $0 in the year ended December 31, 2017. Canadian income tax expense of $11.2 million and $10.1 million was recorded in 2018 and 2017, respectively. The increase in income tax expense was largely a result of the increase in income before taxes generated by DNAG partially offset by the additional taxes recorded during 2017 related to the $12.5 million litigation settlement which did not re-occur in 2018. On December 22, 2017, the U.S. enacted the Tax Act that instituted fundamental changes to the taxation on multinational corporations. The impact of the Tax Act on our financial results was not material given OSUR has a full valuation allowance against its total U.S. deferred tax assets and due to the net operating losses (“NOLs”) and tax credits that are being generated by the U.S. entity. +Liquidity and Capital Resources +December 31, +2019 +2018 +(In thousands) +Cash and cash equivalents +$ +75,715 +$ +88,438 +Available for sale securities +114,043 +112,886 +Working capital +191,837 +191,332 +Our cash, cash equivalents, and available-for-sale securities decreased to $189.8 million at December 31, 2019 from $201.3 million at December 31, 2018. Our working capital increased to $191.8 million at December 31, 2019 from $191.3 million at December 31, 2018. +During 2019, we generated $9.8 million in cash from operating activities. Our net income of $16.7 million included the pre-tax gain on the sale of our cryosurgical systems business of $10.2 million, non-cash charges for stock-based compensation expense of $4.1 million, depreciation and amortization expense of $7.3 million, and a provision for doubtful accounts of $2.2 million offset by a non-cash benefit for the change in the estimated fair value of acquisition-related contingent consideration of $664,000 and other non-cash benefits of $498,000. Offsetting the adjusted net income was a $2.2 million increase in accounts receivable largely resulting from an increase in product orders placed during the fourth quarter of 2019, a decrease in accrued expenses and other liabilities of $4.0 million largely due to the submission of tax payments to the Canadian taxing authorities and payment of our 2018 management incentive bonuses, a decrease in accounts payable associated with the timing of invoices paid during the year, and an increase in inventory of $1.3 million in order to meet contractual obligations associated with our HCV raw materials. +Net cash used in investing activities was $19.8 million for the year ended December 31, 2019, which reflects $92.2 million used to purchase investments, $23.8 million to acquire CoreBiome, Novosanis, and Diversigen, and $9.3 million to acquire property and equipment partially offset by $93.5 million in proceeds from the maturities and redemptions of investments and $12.0 million from the sale of the cryosurgical systems business . +Net cash used in financing activities was $4.7 million in 2019, which resulted from $3.7 million used for the repurchase of common stock to satisfy withholding taxes related to the vesting of restricted and performance award shares partially offset by $724,000 to payoff loans which were assumed in the acquisition of Novosanis . +On March 29, 2019, we terminated our credit agreement with a commercial bank, which was initially entered into on September 30, 2016 (as amended in December 2017) and had a maturity date of September 30, 2019. The credit agreement was terminated because of our strong cash position and the availability of alternative financing sources, which, if needed would be more suited to our business needs. There were no borrowings outstanding at December 31, 2018 or at the time of termination of the credit agreement. +We expect current balances of cash and cash equivalents and available-for-sale securities to be sufficient to fund our current and foreseeable operating and capital needs. Our cash requirements, however, may vary materially from those now planned due to many factors, including, but not limited to, the scope and timing of future strategic acquisitions, the progress of our research and development programs, the scope and results of clinical testing, the cost of any future litigation, the magnitude of capital expenditures, changes in existing and potential relationships with business partners, the timing and cost of obtaining regulatory approvals, the timing and cost of future stock purchases, the costs involved in obtaining and enforcing patents, proprietary rights and any necessary licenses, the cost and timing of expansion of sales and marketing activities, market acceptance of new products, competing technological and market developments, the impact of the current economic environment and other factors. In addition, $90.7 million or 48% of our $189.8 million in cash, cash equivalents, and available-for-sale securities belongs to our Canadian subsidiary. Repatriation of such cash into the United States exceeding certain levels could have adverse tax consequences. +58 +Contractual Obligations and Commercial Commitments +The following sets forth our approximate aggregate obligations as of December 31, 2019 (in thousands) for future payments under contracts and other contingent commitments, for the year 2020 and beyond: +Payments due by December 31, +Contractual Obligations +Total +2020 +2021 +2022 +2023 +2024 +Employment contracts 1 +5,561 +3,110 +1,682 +460 +309 +— +Purchase obligations 2 +10,337 +10,279 +20 +20 +18 +— +Total contractual obligations +$ +15,898 +$ +13,389 +$ +1,702 +$ +480 +$ +327 +$ +— +1 +Represents salary payments payable under the terms of employment agreements executed by us with certain executives. See Note 15 of the Notes to the consolidated financial statements included herein +2 +Represents payments required by non-cancellable purchase orders or supply agreements related to inventory, supplies, capital expenditures and other goods or services. The supply agreements are cancellable within a specified number of days of written notice to the supplier. See Note 15 of the Notes to the consolidated financial statements included herein. +Off-Balance Sheet Arrangements . We do not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934, as amended. +Critical Accounting Policies and Estimates +This Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires that we make judgements and estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our judgments and estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. +Our significant accounting policies are described in Note 2 of the Notes to the consolidated financial statements included in Item 15 of this Annual Report. We consider the following accounting policies, which have been discussed with our Audit Committee, to be most critical in understanding the more complex judgments that are involved in preparing our financial statements and the uncertainties that could impact our results of operations, financial condition and cash flows. +Revenue Recognition . In January 2018, we adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, using the modified retrospective method applied to contracts existing as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under the new guidance, while prior period amounts are not adjusted and continue to be reported in accordance with previous guidance. +Revenue from product sales is recognized upon transfer of control of a product to a customer based on an amount that reflects the consideration we are entitled to, net of allowances for any discounts or rebates. +Our net revenues recorded for sales of the OraQuick ® In-Home HIV test represent total gross revenues, less an allowance for expected returns, and customer allowances for cooperative advertising and discounts. The allowance for expected returns is an estimate established by management, based upon currently available information, and is adjusted to reflect known changes in the factors that impact this estimate. Other customer allowances are at contractual rates and are recorded as a reduction of gross revenue when recognized in our consolidated statements of operations. +Other than for sales of our OraQuick® In-Home HIV test to the retail trade and under the terms of a long-term contract with a genomics customer, we generally do not grant product return rights to our customers except for warranty returns. Historically, returns arising from warranty issues have been infrequent and immaterial. Accordingly, we expense warranty returns as incurred. +As a result of the return rights granted to our customers for our OraQuick® In-Home HIV test, we have recorded an estimate of expected returns as a reduction of gross OraQuick® In-Home HIV product revenues in our consolidated statements of operations. This estimate reflects our historical sales experience to retailers and consumers, as well as other retail factors, and is reviewed regularly to ensure that it reflects potential product returns. If actual product returns differ materially from our reserve amount, or if a +59 +determination is made that this product’s distribution would be discontinued in whole or in part by certain retailers, then we would need to adjust our reserve. Should the actual level of product returns vary significantly from our estimates, our operating and financial results could be materially affected. The amounts of returns agreed to under the long-term customer contract are based on a pre-determined percentage of revenues and as such, ou r estimate of expected returns is calculated in accordance with the terms of the contract. As of December 31, 2019 and December 31, 2018, the reserve for sales returns and allowances was $472 and $191, respectively. +We record shipping and handling charges billed to our customers as product revenue and the related expense as cost of products. +Service revenues represent microbiome laboratory testing and analytical services. We recognize revenues and satisfy our performance obligation for services rendered when the testing is complete and the associated results are reported. +In arrangements involving more than one performance obligation, which largely applies to our service revenue stream, each required performance obligation is evaluated to determine whether it qualifies as a distinct performance obligation based on whether (i) the customer can benefit from the good or service either on its own or together with other resources that are readily available and (ii) the good or services is separately identifiable from other promises in the contract. The consideration under the arrangement is then allocated to each separate distinct performance obligation based on their respective relative stand-alone selling price. The estimated selling price of each deliverable reflects our best estimate of what the selling price would be if the deliverable was regularly sold by us on a stand-alone basis or using an observable cost plus margin approach if selling price on a stand-alone basis is not available. The consideration allocated to each distinct performance obligation is recognized as revenue when control is transferred for the related goods or services or when the performance obligation has been satisfied. +Other revenues consist primarily of royalty income, funding of research and development efforts and cost reimbursements under a charitable support agreement. Royalties from licensees are based on third-party sales of licensed products and are recorded when the related third-party product sale occurs. Funding and charitable support reimbursements are recorded as the activities are being performed in accordance with the respective agreements. +We record deferred revenue when funds are received prior to the recognition of the associated revenue. Deferred revenue as of December 31, 2019 and 2018 includes customer prepayments of $1,904 and $2,057, respectively. Deferred revenue as of December 31, 2019 and 2018 also included $1,809 and $1,464, respectively, associated with a long-term contract that has variable pricing based on volume. The average price over the life of contract was determined and revenue is recognized at that rate when the product is delivered to the customer. +Our payment terms vary by the type and location of our customer and products or services offered. Payment terms differ by jurisdiction and customer but payment is generally required in a term ranging from 30 to 120 days from date of shipment or satisfaction of the performance obligation. +For certain products or services and customer types, we may require payment before the products are delivered or services are rendered to the customer. +Taxes assessed by governmental authorities, such as sales or value-added taxes, are excluded from product revenues. +Sales commissions are expensed when incurred if the amortization period is one year or less. These costs are recorded in sales and marketing expense in the consolidated statements of operations. If the amortization period exceeds one year, we defer the cost of the commission and expense it over the life of the related sales contract . +Inventories . Our inventories are stated at the lower of cost or net realizable value, with cost determined on a first-in, first-out basis, and include the cost of raw materials, labor and overhead. The majority of our inventories are subject to expiration dating, which can be extended in certain circumstances. We continually evaluate quantities on hand and the carrying value of our inventories to determine the need for reserves for excess and obsolete inventories, based on prior experience as well as estimated forecasts of product sales. When factors indicate that impairment has occurred, either a reserve is established against the inventories’ carrying value or the inventories are completely written off, as in the case of lapsing expiration dates. In addition to reserving for these items identified through specific identification procedures, we also reserve for unidentified scrap or spoilage based on historical write-off rates. +During 2019, 2018, and 2017 we wrote-off inventory which had a cost of $1.3 million, $1.3 million and $3.3 million, respectively. These write-offs were a result of quality, scrap and product expiration issues. Although we make every effort to ensure the accuracy of +60 +our forecasts of future product demand, any significant unanticipated changes in demand could have a significant impact on the carrying value of our inventories and reported operating results. +Deferred Tax Assets and Liabilities. In 2017, we re-measured our federal net deferred tax asset based on the federal rate at which they were expected to reverse in the future which is 21% pursuant to the Tax Act. We also re-measured our state net deferred asset since the future federal benefit was reduced to 21%. +At December 31, 2019, we had federal Net Operating Loss (“NOL”) carryforwards of $36.4 million. The net deferred tax assets, before the valuation allowance, associated with these NOLs and other temporary differences were $13.7 million at December 31, 2019. Net operating losses will begin to expire in 2030. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the period in which those temporary differences become deductible or the NOLs and credit carryforwards can be utilized. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. +We currently have a full valuation allowance recorded against our total U.S. deferred tax asset as we had determined in 2008 that it was more likely than not that we would not realize the benefits associated with our deferred tax asset in the immediate future. Each year, we continue to reevaluate our valuation allowance position and believe that it is more likely than not that our U.S. deferred income tax asset will not be realized in the immediate future. As such, we maintain a full valuation allowance as of December 31, 2019 and 2018 against our deferred tax assets associated with the operations subject to income tax in the U.S. +The Tax Reform Act of 1986 contains provisions under Internal Revenue Code (“IRC”) Section 382 that limit the annual amount of federal and state NOLs available to be used in any given year in the event of a significant change in ownership. Our ability to use our federal and state NOL carryforwards to offset future federal income tax obligations could be limited by changes in the ownership of our stock. The Company does not believe, however, that there is a Section 382 limitation that will impair our future ability to utilize NOLs to offset our future taxable income and the Company continues to review ownership changes on an annual basis. +Business Combinations and Contingent Consideration . Acquired businesses are accounted for using the acquisition method of accounting, which requires that the purchase price be allocated to the net assets acquired at their respective fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Amounts allocated to contingent consideration are recorded to the balance sheet at the date of acquisition based on their relative fair values. The purchase price allocation requires us to make significant estimates and assumptions, especially at the acquisition date, with respect to intangible assets. Although we believe the assumptions and estimates we have made are reasonable, they are based in part on historical experience and information obtained from the management of the acquired companies and are inherently uncertain. +We account for contingent consideration in accordance with applicable guidance provided within the business combination accounting guidance. As part of our consideration for the CoreBiome, Novosanis, and Diversigen acquisitions, we are contractually obligated to pay certain consideration resulting from the outcome of future events. Therefore, we are required to update our underlying assumptions each reporting period, based on new developments, and record such contingent consideration liabilities at fair value until the contingency is resolved. Changes in the fair value of the contingent consideration liabilities are recognized each reporting period and included in our consolidated statements of operations. Our estimates of fair value are based on assumptions we believe to be reasonable, but the assumptions are uncertain and involve significant judgment by management. Updates to these assumptions could have a significant impact on our results of operations in any given period and any updates to the fair value of the contingent consideration could differ materially from the previous estimates. +Examples of critical estimates used in valuing certain intangible assets and contingent consideration include: +• +future expected cash flows from sales and acquired developed technologies; +• +the acquired company's trade name and customer relationships as well as assumptions about the period of time the acquired trade name and customer relationships will continue to be used in the combined company's portfolio; +• +the probability of meeting the future events; and +• +discount rates used to determine the present value of estimated future cash flows. +These estimates are inherently uncertain and unpredictable, and if different estimates were used the purchase price for the acquisition could be allocated to the acquired assets and liabilities differently from the allocation that we have made. In addition, unanticipated +61 +events and circumstances may occur, which may affect the accuracy or validity of such estimates, and if such events occur we may be required to record a charge against the value ascribed to an acquired asset or an increase in the amounts recorded for assumed liabilities. +ITEM 7A. +Quantitative and Qualitative Disclosures About Market Risk. +We do not hold any amounts of derivative financial instruments or derivative commodity instruments and, accordingly, we have no material derivative risk to report under this Item. +As of December 31, 2019, we did not have any foreign currency exchange contracts or purchase currency options to hedge local currency cash flows. Sales denominated in foreign currencies comprised 4.0% of our total revenues for the year ended December 31, 2019. We do have foreign currency exchange risk related to our operating subsidiaries in Canada and in Belgium. The principal foreign currencies in which we conduct business are the Canadian dollar and the Euro. Fluctuations in the exchange rate between the U.S. dollar and these foreign currencies could affect year-to-year comparability of operating results and cash flows. Our foreign subsidiaries had net assets, subject to translation, of $140.8 million in U.S. Dollars, which are included in the Company’s consolidated balance sheet as of December 31, 2019. A 10% unfavorable change in the Canadian-to-U.S. dollar and Euro-to-U.S. dollar exchange rates would have decreased our comprehensive income by approximately $11.9 million in the year ended December 31, 2019. +ITEM 8. +Financial Statements and Supplementary Data. +Information with respect to this Item is contained in our Consolidated Financial Statements included in Item 15 of this Annual Report on Form 10-K. +ITEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +ITEM 9A. +Controls and Procedures. +(a) Evaluation of Disclosure Controls and Procedures . +The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of December 31, 2019. Based on that evaluation, the Company’s management, including such officers, concluded that as of December 31, 2019 the Company’s disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. +(b) Management’s Report on Internal Control Over Financial Reporting. +The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of the Company’s management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework, our management concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles as of December 31, 2019. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +The Company acquired CoreBiome, Inc., Novosanis NV, and Diversigen, Inc. collectively, the “acquired companies,” during 2019, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, the acquired companies’ representing approximately 11.7% of total assets and 4.0% of total revenues of the Company as of and for the year ended December 31, 2019. Management plans to fully integrate the operations of these businesses into the assessment of the effectiveness of the Company’s internal control over financial reporting in 2020. +62 +The effectiveness of our internal control over financial reporting as of December 31, 201 9 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included below. +(c) Changes in Internal Control Over Financial Reporting . +There were no changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +(d) Report of Independent Registered Public Accounting Firm . +To the Stockholders and Board of Directors +OraSure Technologies, Inc.: +Opinion on Internal Control Over Financial Reporting +We have audited OraSure Technologies, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission . In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and related notes (collectively, the consolidated financial statements), and our report dated March 2, 2020 expressed an unqualified opinion on those consolidated financial statements. +The Company acquired CoreBiome, Inc., Novosanis NV and Diversigen, Inc. (collectively, the “Acquired Companies”) during 2019, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, the Acquired Companies’ internal control over financial reporting associated with 11.7% of total assets and 4.0% of total revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2019. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of the Acquired Companies. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding +63 +prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Philadelphia, Pennsylvania +March 2, 2020 +ITEM 9B. +Other Information. +Not applicable. +64 +PART III +We have omitted from Part III the information that will appear in our Definitive Proxy Statement for our 2019 Annual Meeting of Stockholders (the “Proxy Statement”), which will be filed within 120 days after the end of our fiscal year pursuant to Regulation 14A. +ITEM 10. +Directors, Executive Officers and Corporate Governance. +Certain information required by this Item is incorporated by reference to the information under the captions “Proposal No. 1. Election of Directors,” “Corporate Governance - Governance Guidelines and Code of Conduct,” “Corporate Governance – Committees of the Board,” “Executive Officers,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement. +Our Board of Directors has adopted a Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, as well as to the members of our Board of Directors and our other officers and employees. This Code of Business Conduct and Ethics is available on our website at www.orasure.com . We intend to satisfy the amendment and waiver disclosure requirements under applicable securities regulations by posting any amendments of, or waivers to, the Code of Business Conduct and Ethics on our website. +ITEM 11. +Executive Compensation. +The information required by this Item is incorporated by reference to the information under the captions “Compensation Committee Matters” (including the “Compensation Committee Report”), “Compensation Discussion and Analysis,” “Compensation Tables,” “Employment Agreements and Potential Payments Upon Termination or Change in Control,” and “Director Compensation” in the Proxy Statement. +ITEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +The information required by this Item with respect to the securities ownership of certain beneficial owners and management, and equity compensation plan information, is incorporated by reference to the information under the captions “Stock Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information” in the Proxy Statement. +ITEM 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated by reference to the information under the captions “Transactions with Related Persons” and “Corporate Governance - Director Independence” in the Proxy Statement. +ITEM 14. +Principal Accountant Fees and Services. +The information required by this Item is incorporated by reference to the information under the caption “Audit Committee Matters” in the Proxy Statement. +65 +PART IV +ITEM 15. +Exhibits and Consolidated Financial Statement Schedules. +(a)(1) and (a)(2). Consolidated Financial Statements and Schedules . For a list of the consolidated financial statements filed herewith, see the Index to Consolidated Financial Statements following the signature page to this Annual Report. No schedules are included with the consolidated financial statements because the required information is inapplicable or is presented in the consolidated financial statements or related notes thereto. +(a)(3). Exhibits . +Exhibit +Number +Exhibit +2.1 +Asset Purchase Agreement, dated August 15, 2019, between OraSure Technologies, Inc. and CryoConcepts LP is incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed August 19, 2019. +3.1.1 +Certificate of Incorporation of OraSure Technologies, Inc. is incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 (No. 333-39210), filed June 14, 2000. +3.1.2 +Certificate of Amendment to Certificate of Incorporation dated May 23, 2000 is incorporated by reference to Exhibit 3.1.1 to the Company’s Registration Statement on Form S-4 (No. 333-39210), filed June 14, 2000. +3.2 +Bylaws of OraSure Technologies, Inc., as amended and restated as of February 19, 2018, are incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. +4.1 +Description of Securities . +10.1 +Employment Agreement dated as of January 3, 2018, between OraSure Technologies, Inc. and Stephen S. Tang, Ph.D., is incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 4, 2018.* +10.2 +Employment Agreement, dated as of May 4, 2018, between the Company and Roberto Cuca is incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 4, 2018. * +10.3 +Employment Agreement, dated as of July 1, 2004, between OraSure Technologies, Inc. and Jack E. Jerrett, is incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004.* +10.4 +Amendment No. 1 to Employment Agreement, dated as of December 16, 2008, between the Company and Jack E. Jerrett, is incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed December 19, 2008.* +10.5 +Amendment No. 2 to the Employment Agreement, dated as of December 15, 2010, between the Company and Jack E. Jerrett, is incorporated by reference to Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.* +10.6 +Amendment No. 3 to Employment Agreement, dated as of March 27, 2015, between the Company and Jack E. Jerrett is incorporated by reference to Exhibit 99.3 to the Company’s current Report on Form 8-K filed March 31, 2015.* +10.7 +Employment Agreement, dated as of January 3, 2011, between the Company and Anthony Zezzo II is incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.* +10.8 +Employment Agreement, dated as of January 1, 2019, between Kathleen G. Weber, DNA Genotek, Inc. and OraSure Technologies, Inc. is incorporated by reference to Exhibit 10.21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.* +10.9 +Description of Non-Employee Director Compensation Policy, as amended, is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed May 11, 2018. * +10.10 +Description of Non-Employee Director Compensation Policy, as amended, is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed May 23, 2019.* +10.11 +Description of Non-Employee Director Compensation Policy, as amended, is incorporated by reference to Item 5.02 to the Company’s Current Report on form 8-K filed August 14, 2019.* +10.12 +Amended and Restated Epitope, Inc. 1991 Stock Award Plan is incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.* +66 +Exhibit +Number +Exhibit +10.1 3 +OraSure Technologies, Inc. Employee Incentive and Non-Qualified Stock Option Plan, as amended and restated effective September 29, 2000, is incorporated by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000.* +10.14 +Amended and Restated OraSure Technologies, Inc. Stock Award Plan, effective February 21, 2017, is incorporated by reference to Exhibit A to the Company’s Proxy Statement, filed April 5, 2017, for the 2017 Annual Meeting of Stockholders.* +10.15 +Form of Restricted Share Award Agreement (Executive Officers – Employment Agreements) is incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.* +10.16 +Form of Restricted Unit Award Agreement (Executive Officers – Employment Agreements) is incorporated by reference to Exhibit 10.27 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. * +10.17 +Form of Restricted Share Grant Agreement (Non-Employee Directors) is incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.* +10.18 +Nonqualified Stock Option Award General Terms and Conditions (Executive Officers) is incorporated by reference to Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.* +10.19 +Nonqualified Stock Option Award General Terms and Conditions (Non-Employee Directors) is incorporated by reference to Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.* +10.20 +Description of the OraSure Technologies, Inc. 2019 Incentive Plan is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed May 8, 2019.* +10.21 +Description of the OraSure Technologies, Inc. 2020 Incentive Plan is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed February 21, 2020.* +10.22 +Description of Amendment to Long-Term Incentive Policy is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed August 17, 2018.* +10.23 +Description of Long-Term Incentive Policy, as amended, is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed February 14, 2019.* +10.24 +Description of Long-Term Incentive Policy and 2019 Award Performance Measures is incorporated by reference to Item 5.02 to the Company’s Current Report on Form 8-K filed February 21, 2020.* +10.25 +OraSure Technologies, Inc. Deferred Compensation Plan is incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed December 21, 2011.* +10.26 +Adoption Agreement related to OraSure Technologies, Inc. Deferred Compensation Plan is incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed December 21, 2011.* +10.27 +Amended and Restated Code of Business Conduct and Ethics of OraSure Technologies, Inc. is incorporated by reference to Exhibit 14.1 to the Company’s Current Report on Form 8-K filed August 14, 2019. +21 +Subsidiaries of the Company are incorporated by reference to Exhibit 21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. +23 +Consent of KPMG LLP. +24 +Powers of Attorney. +31.1 +Certification of Stephen S. Tang, Ph.D. required by Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. +31.2 +Certification of Roberto Cuca required by Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. +32.1 +Certification of Stephen S. Tang, Ph.D. required by Rule 13a-14(b) or Rule 15a-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +32.2 +Certification of Roberto Cuca required by Rule 13a-14(b) or Rule 15a-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +67 +101.INS +Inline XBRL Instance Document +101.SCH +Inline XBRL Taxonomy Extension Schema Document +101.CAL +Inline XBRL Taxonomy Extension Calculation Linkbase Document +101.DEF +Inline XBRL Taxonomy Extension Definition Linkbase Document +101.LAB +Inline XBRL Taxonomy Extension Label Linkbase Document +101.PRE +Inline XBRL Taxonomy Extension Presentation Linkbase document +104 +The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, has been formatted in Inline XBRL. +* +Management contract or compensatory plan or arrangement. +ITEM 16. +Form 10-K Summary. +None +68 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 2, 2020. +ORASURE TECHNOLOGIES, INC. +By: +/s/ Stephen S. Tang +Stephen S. Tang, Ph.D. +President and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed on March 2, 2020, by the following persons on behalf of the Registrant and in the capacities indicated. +SIGNATURE +TITLE +/s/ Stephen S. Tang +President, Chief Executive Officer and Director +(Principal Executive Officer) +Stephen S. Tang, Ph.D. +/s/ Roberto Cuca +Chief Financial Officer +(Principal Financial Officer) +Roberto Cuca +/s/ Michele Miller +Vice President, Finance and Controller +(Principal Accounting Officer) +Michele Miller +*MARA ASPINALL +Mara Aspinall +Director +*MICHAEL CELANO +Michael Celano +Director +*JAMES A. DATIN +James A. Datin +Director +*EAMONN P. HOBBS +Eamonn P. Hobbs +Director +*RONNY B. LANCASTER +Ronny B. Lancaster +Director +*CHARLES W. PATRICK +Charles W. Patrick +Director +*ARADHANA SARIN +Aradhana Sarin +Director +*By: +/s/ Jack E. Jerrett +Jack E. Jerrett +(Attorney-in-Fact) +69 +Index to Consolidated Financial Statements +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets +F-4 +Consolidated Statements of Income +F-5 +Consolidated Statements of Comprehensive Income +F-6 +Consolidated Statements of Stockholders’ Equity +F-7 +Consolidated Statements of Cash Flows +F-8 +Notes to the Consolidated Financial Statements +F-9 +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Stockholders and Board of Directors +OraSure Technologies, Inc.: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of OraSure Technologies, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Change in Accounting Principle +As discussed in Note 10 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update No. 2016-02, Leases. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +Assessment of the acquisition-date fair value of developed technology +As discussed in Note 3 to the consolidated financial statements, the Company acquired a business in January 2019. As a result of this transaction, the Company acquired a developed technology intangible asset. The acquisition date fair value of the developed technology was $5.0 million. The purchase price of the business combination was allocated to the assets acquired and liabilities assumed, in each case based on estimates of their respective fair values at the acquisition date. Fair values of intangible assets are estimated using valuation models prepared by the Company with the assistance of third-party specialists. +F-2 +We identified the assessment of the acquisition-date fair value of the developed technology for the business acquisition as a critical audit matter. Assessing the estimated fair value of the developed technology resulted in the application of a high degree of auditor judgment. The revenue growth rates and the discount rate used to determine the fair value of the developed technology were challenging to evaluate as there was limited observable market information and minor changes to those assumptions could have a significant effect on the acquisition-date fair value of the intangible asset. +The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s business combinations process, including controls related to the determination of the fair value of the acquired intangible assets and the related revenue growth rates and the discount rate. We evaluated the Company’s projected revenue growth rates for the developed technology by comparing the growth assumptions to historical growth rates of comparable products. We compared the acquired business’ forecasted revenue growth rates to their actual historical results. In addition, we involved a valuation professional with specialized skill and knowledge, who assisted in: +- +evaluating the Company’s discount rate, by comparing it against a discount rate range that was independently developed using publicly available market data; and +- +developing an estimate of the developed technology fair value using the Company’s cash flow forecast for the developed technology and an independently developed discount rate, and compared the results of our estimate to the Company’s fair value estimate. +Evaluation of net realizable value adjustments to inventories for excess or obsolescence +As discussed in Notes 2 and 5 to the consolidated financial statements, the Company has inventories with a carrying value of $23.2 million as of December 31, 2019. Inventories are stated at the lower of cost or net realizable value, with cost determined on a first-in, first-out basis. The majority of the inventories are subject to expiration dating, which can be extended in certain circumstances. The Company continually evaluates quantities on hand and the carrying value of inventories to determine the need for net realizable value adjustments for excess and obsolete inventories, based on prior experience as well as forecasts of product sales. +We identified the evaluation of net realizable value adjustments to inventories for excess or obsolescence as a critical audit matter. The Company’s estimates regarding forecasted sales and the resulting inventory consumption and considerations related to the ability to extend inventory expiration dates result in the application of a high degree of auditor judgment. +The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s process for determining net realizable value adjustments for inventory excess or obsolescence. We evaluated historic write-off activity as compared to total inventories. For a selection of inventory items, we compared the Company’s historic estimates of net realizable value adjustments for excess and obsolescence to the actual physical inventory disposals to evaluate the Company’s ability to accurately estimate the net realizable value adjustments. We evaluated the Company’s ability to forecast sales by comparing prior period sales forecasts to actual results. In addition, we selected inventory items from the underlying data used in the Company’s analysis, and evaluated the Company’s determination of net realizable value adjustments for those items using historic inventory consumption, the expiration date of certain on-hand inventory items and the ability to extend expiration dates. +/s/ KPMG LLP +We have served as the Company’s auditor since 2002. +Philadelphia, Pennsylvania +March 2, 2020 +F-3 +ORASURE TECHNOLOGIES, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(in thousands, except per share amounts) +December 31, 2019 +December 31, 2018 +ASSETS +Current Assets: +Cash and cash equivalents +$ +75,715 +$ +88,438 +Short-term investments +80,623 +68,134 +Accounts receivable, net of allowance for doubtful accounts of $ 2,666 and $ 418 +36,948 +34,842 +Inventories +23,155 +22,888 +Prepaid expenses +2,433 +1,925 +Other current assets +5,676 +3,085 +Total current assets +224,550 +219,312 +Noncurrent Assets: +Property, plant and equipment, net +30,339 +24,299 +Operating right-of-use assets, net +4,996 +— +Finance right-of-use assets, net +1,951 +— +Intangible assets, net +14,674 +5,137 +Goodwill +36,201 +18,521 +Long-term investments +33,420 +44,752 +Other noncurrent assets +3,164 +3,550 +Total noncurrent assets +124,745 +96,259 +TOTAL ASSETS +$ +349,295 +$ +315,571 +LIABILITIES AND STOCKHOLDERS' EQUITY +Current Liabilities: +Accounts payable +$ +9,567 +$ +10,598 +Deferred revenue +3,713 +3,521 +Accrued expenses +14,288 +13,861 +Finance lease liability +613 +— +Operating lease liability +1,032 +— +Acquisition-related contingent consideration obligation +3,500 +— +Total current liabilities +32,713 +27,980 +Noncurrent Liabilities: +Finance lease liability +1,372 +— +Operating lease liability +4,206 +— +Acquisition-related contingent consideration obligation +112 +— +Other noncurrent liabilities +2,848 +3,312 +Deferred income taxes +899 +901 +Total noncurrent liabilities +9,437 +4,213 +TOTAL LIABILITIES +42,150 +32,193 +COMMITMENTS AND CONTINGENCIES (Note 15) +STOCKHOLDERS' EQUITY +Preferred stock, par value $ .000001 , 25,000 shares authorized, none issued +— +— +Common stock, par value $ .000001 , 120,000 shares authorized, 61,731 and +61,276 shares issued and outstanding +— +— +Additional paid-in capital +401,814 +401,273 +Accumulated other comprehensive loss +( 12,136 +) +( 18,706 +) +Accumulated deficit +( 82,533 +) +( 99,189 +) +Total stockholders' equity +307,145 +283,378 +TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY +$ +349,295 +$ +315,571 +See accompanying notes to the consolidated financial statements. +F-4 +ORASURE TECHNOLOGIES, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(in thousands, except per share amounts) +For the years ended December 31, +2019 +2018 +2017 +NET REVENUES: +Products and services +$ +148,073 +$ +165,428 +$ +161,988 +Other +6,532 +16,315 +5,076 +154,605 +181,743 +167,064 +COST OF PRODUCTS SOLD +60,022 +68,130 +68,108 +Gross profit +94,583 +113,613 +98,956 +OPERATING EXPENSES: +Research and development +19,629 +16,250 +13,365 +Sales and marketing +31,869 +30,609 +28,532 +General and administrative +35,287 +38,325 +29,321 +Gain on litigation settlement +— +— +( 12,500 +) +Change in the estimated fair value of acquisition-related contingent consideration +( 664 +) +— +— +Gain on sale of business +( 10,149 +) +— +— +75,972 +85,184 +58,718 +Operating income +18,611 +28,429 +40,238 +OTHER INCOME +2,720 +3,287 +794 +Income before income taxes +21,331 +31,716 +41,032 +INCOME TAX EXPENSE +4,675 +11,320 +10,084 +NET INCOME +$ +16,656 +$ +20,396 +$ +30,948 +EARNINGS PER SHARE: +BASIC +$ +0.27 +$ +0.33 +$ +0.52 +DILUTED +$ +0.27 +$ +0.33 +$ +0.51 +SHARES USED IN COMPUTING EARNINGS PER SHARE: +BASIC +61,675 +61,112 +59,050 +DILUTED +62,170 +62,532 +61,024 +See accompanying notes to the consolidated financial statements. +F-5 +ORASURE TECHNOLOGIES, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(in thousands) +For the years ended December 31, +2019 +2018 +2017 +NET INCOME +$ +16,656 +$ +20,396 +$ +30,948 +OTHER COMPEHENSIVE INCOME (LOSS) +Currency translation adjustments +5,767 +( 8,003 +) +4,433 +Unrealized gain (loss) on marketable securities +803 +( 363 +) +( 553 +) +COMPREHENSIVE INCOME +$ +23,226 +$ +12,030 +$ +34,828 +See accompanying notes to the consolidated financial statements. +F-6 +ORASURE TECHNOLOGIES, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY +For the years ended December 31, 2019, 2018 and 2017 +(in thousands) +Common Stock +Additional +Paid-in +Accumulated +Other +Comprehensive +Accumulated +Shares +Amount +Capital +Loss +Deficit +Total +Balance at January 1, 2017 +56,001 +$ +— +$ +350,528 +$ +( 14,220 +) +$ +( 150,458 +) +$ +185,850 +Common stock issued upon exercise +of options +4,413 +— +31,670 +— +— +31,670 +Vesting of restricted stock +378 +— +— +— +— +— +Purchase and retirement of common shares +( 130 +) +— +( 1,240 +) +— +— +( 1,240 +) +Compensation cost for restricted stock +— +— +2,705 +— +— +2,705 +Compensation cost for stock option +grants +— +— +2,045 +— +— +2,045 +Compensation cost for performance +stock units +— +— +2,223 +— +— +2,223 +Net income +— +— +— +— +30,948 +30,948 +Currency translation adjustments +— +— +— +4,433 +— +4,433 +Unrealized loss on marketable securities +— +— +— +( 553 +) +— +( 553 +) +Balance at December 31, 2017 +60,662 +— +387,931 +( 10,340 +) +( 119,510 +) +258,081 +Adoption of ASU 2014-9 +( 75 +) +( 75 +) +Common stock issued upon exercise +of options +227 +— +1,697 +— +— +1,697 +Vesting of restricted stock +578 +— +— +— +— +— +Purchase and retirement of common shares +( 191 +) +— +( 3,592 +) +— +— +( 3,592 +) +Compensation cost for restricted stock +— +— +6,357 +— +— +6,357 +Compensation cost for stock option grants +— +— +2,163 +— +— +2,163 +Compensation cost for performance +stock units +— +— +6,717 +— +— +6,717 +Net income +— +— +— +— +20,396 +20,396 +Currency translation adjustments +— +— +— +( 8,003 +) +— +( 8,003 +) +Unrealized loss on marketable securities +— +— +— +( 363 +) +— +( 363 +) +Balance at December 31, 2018 +61,276 +— +401,273 +( 18,706 +) +( 99,189 +) +283,378 +Common stock issued upon exercise +of options +27 +— +196 +— +— +196 +Vesting of restricted stock and performance stock units +717 +— +— +— +— +— +Purchase and retirement of common shares +( 289 +) +— +( 3,712 +) +— +— +( 3,712 +) +Compensation cost for restricted stock +— +— +2,979 +— +— +2,979 +Compensation cost for stock option grants +— +— +1,161 +— +— +1,161 +Compensation cost for performance stock units +— +— +( 83 +) +— +— +( 83 +) +Net income +— +— +— +— +16,656 +16,656 +Currency translation adjustments +5,767 +5,767 +Unrealized gain on marketable securities +— +— +— +803 +— +803 +Balance at December 31, 2019 +61,731 +$ +— +$ +401,814 +$ +( 12,136 +) +$ +( 82,533 +) +$ +307,145 +See accompanying notes to the consolidated financial statements. +F-7 +ORASURE TECHNOLOGIES, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(in thousands) +For the years ended December 31, +2019 +2018 +2017 +OPERATING ACTIVITIES: +Net income +$ +16,656 +$ +20,396 +$ +30,948 +Adjustments to reconcile net income to net cash provided by +operating activities: +Stock-based compensation +4,057 +15,237 +6,973 +Depreciation and amortization +7,339 +6,451 +6,075 +Other non-cash amortization +391 +771 +327 +Provision for doubtful accounts +2,248 +( 53 +) +( 13 +) +Unrealized foreign currency (gain) loss +385 +( 400 +) +156 +Interest expense on finance leases +36 +— +— +Deferred income taxes +( 1,457 +) +( 919 +) +( 649 +) +Loss (gain) on sale of fixed assets +147 +— +( 25 +) +Gain on sale of business +( 10,149 +) +— +— +Change in the estimated fair value of contingent earn-out consideration +( 664 +) +— +— +Changes in assets and liabilities +Accounts receivable +( 2,210 +) +6,688 +( 22,103 +) +Inventories +( 1,324 +) +( 3,857 +) +( 7,391 +) +Prepaid expenses and other assets +200 +( 366 +) +( 384 +) +Accounts payable +( 1,537 +) +208 +5,157 +Deferred revenue +( 297 +) +2,240 +( 93 +) +Accrued expenses and other liabilities +( 4,017 +) +( 7,306 +) +9,178 +Net cash provided by operating activities +9,804 +39,090 +28,156 +INVESTING ACTIVITIES: +Purchases of investments +( 92,173 +) +( 163,763 +) +( 161,269 +) +Proceeds from maturities and redemptions of investments +93,491 +152,680 +69,253 +Purchases of property and equipment +( 9,314 +) +( 6,344 +) +( 4,337 +) +Acquisition of businesses, net of cash acquired +( 23,801 +) +— +— +Proceeds from sale of business +12,000 +— +— +Net cash used in investing activities +( 19,797 +) +( 17,427 +) +( 96,353 +) +FINANCING ACTIVITIES: +Repayments of loans +( 724 +) +— +— +Cash payments for lease liability +( 442 +) +— +— +Proceeds from exercise of stock options +196 +1,701 +31,675 +Repurchase of common stock +( 3,712 +) +( 3,592 +) +( 1,240 +) +Net cash provided by (used in) financing activities +( 4,682 +) +( 1,891 +) +30,435 +EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH +1,952 +( 4,203 +) +841 +NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS, +AND RESTRICTED CASH +( 12,723 +) +15,569 +( 36,921 +) +CASH, CASH EQUIVALENTS, AND RESTRICTED CASH, +BEGINNING OF PERIOD +88,438 +72,869 +109,790 +CASH, CASH EQUIVALENTS, AND RESTRICTED CASH, END +OF PERIOD +$ +75,715 +$ +88,438 +$ +72,869 +See accompanying notes to the consolidated financial statements. +F-8 +ORASURE TECHNOLOGIES, INC. AND SUBSIDIARIES +NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS +(in thousands, except per share amounts, unless otherwise indicated) +1. +THE COMPANY: +Our business consists of two segments: our “OSUR” business consists of the development, manufacture, marketing and sale of oral fluid diagnostic products and specimen collection devices using our proprietary technologies, other diagnostic products including immunoassays and other in vitro diagnostic tests that are used on other specimen types. Our molecular collections systems or “DNAG” business consists of the manufacture and sale of kits that are used to collect, stabilize, transport and store samples of genetic material for molecular testing in the consumer genetic, clinical genetic, academic research, pharmacogenomics, personalized medicine, microbiome and animal genetics markets. Our collection kits are also used for the collection of first-void urine for liquid biopsy in the prostate and bladder cancer markets; and in the sexually transmitted infection screening market. In addition, our DNAG business provides microbiome laboratory and bioinformatics services. +Our OSUR diagnostic products include tests for diseases including HIV and Hepatitis C that are performed on a rapid basis at the point of care and tests that are processed in a laboratory. These products are sold in the United States and internationally to various clinical laboratories, hospitals, clinics, and other public health organizations, distributors, government agencies, physicians’ offices, and commercial and industrial entities. Our HIV product is also sold in a consumer-friendly format in the over-the-counter (“OTC”) market in the U.S. and as a self-test to individuals in a number of other countries. We also previously manufactured and sold medical devices used for the removal of benign skin lesions by cryosurgery or freezing. These cryosurgical products were sold in both professional and OTC markets in North America, Europe, Central and South America, and Australia. We sold the assets associated with our cryosurgical systems business to a third party in August 2019. See further discussion at Note 4. +Our DNAG or molecular collection systems business is operated by our subsidiaries, DNA Genotek Inc. (“DNAG”), CoreBiome Inc. (“CoreBiome”), Novosanis NV (“Novosanis”), and Diversigen, Inc. (“Diversigen”). DNAG’s specimen collection devices provide all-in-one systems for the collection, stabilization, transportation and storage of nucleic acids from human saliva and other sample types for genetic and microbiome applications. CoreBiome and Diversigen provide laboratory and bioinformatics services. Novosanis’ Colli-Pee collection device is designed for the volumetric collection of first-void urine for use in research, screening and diagnostics for the liquid biopsy and sexually transmitted infection markets. We also sell research use only sample collection products into the microbiome market and we offer our customers a suite of genomics and microbiome services, which range from package customization and study design optimization to extraction, analysis and reporting services. We serve customers worldwide in the research, healthcare, pharmaceutical and agricultural communities . +2. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: +Principles of Consolidation and Basis of Presentation +The consolidated financial statements include the accounts of OraSure Technologies, Inc. (“OraSure”) and its wholly-owned subsidiaries, DNAG, CoreBiome, Novosanis and Diversigen. All intercompany transactions and balances have been eliminated. References herein to “we,” “us,” “our,” or the “Company” mean OraSure and its consolidated subsidiaries, unless otherwise indicated. +Use of Estimates +The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions about future events. These estimates and underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. Such estimates include the fair value of assets acquired and liabilities assumed for business combinations, the valuation of accounts receivable and inventories and assumptions utilized in impairment testing for intangible assets and goodwill, as well as calculations related to accruals, taxes, contingent consideration and performance-based compensation expense, among others. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis, using historical experience and other factors, which management believes to be reasonable under the circumstances, including the current economic environment. As future events and their effects cannot be determined with precision, actual results could differ significantly from these estimates. Changes in those estimates resulting from continuing changes in the economic environment and other factors will be reflected in the financial statements in those future periods. +F-9 +Supplemental Cash Flow Information +In 2019, 2018 and 2017, we paid income taxes of $ 10,611 , $ 17,126 and $ 4,309 , respectively. +In 2019, 2018 and 2017, we recorded through the consolidated statements of income an increase (decrease) in our allowance for doubtful accounts of $ 2,231 , $( 27 ) and $ 172 , respectively. We had $ 110 , $ 11 and $ 200 in write-offs against the allowance for doubtful accounts in 2019, 2018, and 2017, respectively. +As of December 31, 2019, 2018 and 2017, we had accruals for purchases of property and equipment of $ 660 , $ 964 and $ 449 , respectively. +Investments +We consider all investments in debt securities to be available-for-sale securities. These securities are comprised of guaranteed investment certificates and corporate bonds with purchased maturities greater than ninety days. Available-for-sale securities are carried at fair value, based upon quoted market prices, with unrealized gains and losses, if any, reported in stockholders’ equity as a component of accumulated other comprehensive loss. +The following is a summary of our available-for-sale securities as of December 31, 2019 and 2018: +Amortized +Cost +Gross +Unrealized +Gains +Gross +Unrealized +Losses +Fair Value +December 31, 2019 +Guaranteed investment certificates +$ +24,632 +$ +— +$ +— +$ +24,632 +Corporate bonds +89,525 +271 +( 385 +) +89,411 +Total available-for-sale securities +$ +114,157 +$ +271 +$ +( 385 +) +$ +114,043 +December 31, 2018 +Guaranteed investment certificates +$ +23,096 +$ +— +$ +— +$ +23,096 +Corporate bonds +90,707 +— +( 917 +) +89,790 +Total available-for-sale securities +$ +113,803 +$ +— +$ +( 917 +) +$ +112,886 +At December 31, 2019, maturities of our available- +for-sale securities were as follows: +Less than one year +$ +80,754 +$ +163 +$ +( 294 +) +$ +80,623 +Greater than one year +$ +33,403 +$ +108 +$ +( 91 +) +$ +33,420 +Accounts Receivable +Accounts receivable have been reduced by an estimated allowance for amounts that may become uncollectible in the future. This estimated allowance is based primarily on management’s evaluation of specific balances as they become past due, the financial condition of our customers and our historical experience related to write-offs. +Inventories +Inventories are stated at the lower of cost or net realizable value, with cost determined on a first-in, first-out basis, and include the cost of raw materials, labor and overhead. The majority of our inventories are subject to expiration dating, which can be extended in certain circumstances. We continually evaluate quantities on hand and the carrying value of our inventories to determine the need for reserves for excess and obsolete inventories, based on prior experience as well as estimated forecasts of product sales. When factors indicate that impairment has occurred, either a reserve is established against the inventories’ carrying value or the inventories are completely written off, as in the case of lapsing expiration dates. In addition to reserving for these items identified through specific identification procedures, we also reserve for unidentified scrap or spoilage based on historical write-off rates. +Property, Plant and Equipment +Property, plant and equipment are stated at cost. Additions or improvements are capitalized, while repairs and maintenance are charged to expense. Depreciation and amortization are provided using the straight-line method over the estimated useful lives of the related assets. Buildings are depreciated over twenty to forty years , while computer equipment, machinery and equipment, and +F-10 +furniture and fixtures are depreciated over two to ten years . Building improvements are amortized over their estimated useful lives . When assets are sold, retired, or discarded, the related property amounts are relieved from the accounts, and any gain or loss is recorded in the consolidated statements of income. +Intangible Assets +Intangible assets consist of customer relationships, patents and product rights, developed technology and tradenames. Patents and product rights consist of costs associated with the acquisition of patents, licenses and product distribution rights. Intangible assets are amortized using the straight-line method over their estimated useful lives of five to fifteen years . +Impairment of Long-Lived Assets +We assess the recoverability of our long-lived assets, which include property and equipment and definite-lived intangible assets, by determining whether the carrying value of such assets can be recovered through the sum of the undiscounted future cash flows generated from the use and eventual disposition of the asset. If indicators of impairment exist, we measure the amount of such impairment by comparing the carrying value of the assets to the fair value of these assets, which is generally determined based on the present value of the expected future cash flows associated with the use of the assets. Expected future cash flows reflect our assumptions about selling prices, volumes, costs and market conditions over a reasonable period of time. +Goodwill +Goodwill represents the excess of the purchase price we paid over the fair value of the net tangible and identifiable intangible assets acquired and liabilities assumed in our acquisition of DNAG, CoreBiome, Novosanis and Diversigen. All acquired goodwill has been allocated to our DNAG segment. Goodwill is not amortized but rather is tested annually for impairment or more frequently if we believe that indicators of impairment exist. Current U.S. generally accepted accounting principles permit us to make a qualitative evaluation about the likelihood of goodwill impairment. If we conclude that it is more likely than not that the carrying value of a reporting unit is greater than its fair value, then we would be required to recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. +We performed our annual impairment assessment as of July 31, 2019 utilizing a qualitative evaluation and concluded that it was more likely than not that the fair value of our DNAG reporting unit is greater than its carrying value. We believe we have made reasonable estimates and assumptions to calculate the fair value of our reporting unit. If actual future results are not consistent with management’s estimates and assumptions, we may have to take an impairment charge in the future related to our goodwill. Future impairment tests will continue to be performed annually in the fiscal third quarter, or sooner if a triggering event occurs. As of December 31, 2019, we believe no indicators of impairment exist. +Revenue +In January 2018, we adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, using the modified retrospective method applied to contracts existing as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under the new guidance, while prior period amounts are not adjusted and continue to be reported in accordance with previous guidance. +Upon adoption, we recorded a reduction of $ 75 to the opening balance of accumulated deficit as of January 1, 2018. This adjustment is related to the change in revenue recognition associated with our drug testing kit sales. Sales of our drug testing kits include two performance obligations: sales of the device and laboratory services. Under this new accounting standard, we adjusted the allocation of the transaction price to the performance obligations and the estimate of unexercised rights (“breakage”) associated with the contracts. Prior to the adoption of the new guidance, we used the residual value method to allocate the transaction prices. With the adoption of ASU 2014-09, we allocated transition prices based upon the stand-alone selling price, or fair value method. This change in methodology also impacted our estimated breakage amount. +F-11 +The following table summarizes the impact of the new revenue standard adjustment on our opening balance sheet: +Balance at +New Revenue +Balance at +December 31, 2017 +Standard Adjustment +January 1, 2018 +LIABILITIES AND STOCKHOLDERS' EQUITY +CURRENT LIABILITIES: +Deferred revenue +1,314 +75 +1,389 +STOCKHOLDERS' EQUITY +Accumulated deficit +( 119,510 +) +( 75 +) +( 119,585 +) +The adoption of this new standard had an immaterial impact on our 2018 reported total revenues and operating income, as compared to what would have been reported under the prior standard. We expect the impact of adoption in future periods to continue to be immaterial. Our accounting policies under the new standard were applied prospectively and are described below. +Product sales . Revenue from product sales is recognized upon transfer of control of a product to a customer based on an amount that reflects the consideration we are entitled to, net of allowances for any discounts or rebates. +Our net revenues recorded for sales of the OraQuick ® In-Home HIV test represent total gross revenues, less an allowance for expected returns, and customer allowances for cooperative advertising and discounts. The allowance for expected returns is an estimate established by management, based upon currently available information, and is adjusted to reflect known changes in the factors that impact this estimate. Other customer allowances are at contractual rates and are recorded as a reduction of gross revenue when recognized in our consolidated statements of operations. +Other than for sales of our OraQuick® In-Home HIV test to the retail trade and under the terms of a long-term contract with a genomics customer, we generally do not grant product return rights to our customers except for warranty returns. Historically, returns arising from warranty issues have been infrequent and immaterial. Accordingly, we expense warranty returns as incurred. +As a result of the return rights granted to our customers for our OraQuick® In-Home HIV test, we have recorded an estimate of expected returns as a reduction of gross OraQuick® In-Home HIV product revenues in our consolidated statements of operations. This estimate reflects our historical sales experience to retailers and consumers, as well as other retail factors, and is reviewed regularly to ensure that it reflects potential product returns. If actual product returns differ materially from our reserve amount, or if a determination is made that this product’s distribution would be discontinued in whole or in part by certain retailers, then we would need to adjust our reserve. Should the actual level of product returns vary significantly from our estimates, our operating and financial results could be materially affected. The amounts of returns agreed to under the long-term customer contract are based on a pre-determined percentage of revenues and as such, out estimate of expected returns is calculated in accordance with the terms of the contract. As of December 31, 2019 and December 31, 2018, the reserve for sales returns and allowances was $ 472 and $ 191 , respectively. +We record shipping and handling charges billed to our customers as product revenue and the related expense as cost of products sold. +Service revenues. Service revenues represent microbiome laboratory testing and analytical services. We recognize revenues and satisfy our performance obligation for services rendered when the testing is complete and the associated results are reported +Arrangements with multiple-performance obligations . In arrangements involving more than one performance obligation, which largely applies to our service revenue stream, each required performance obligation is evaluated to determine whether it qualifies as a distinct performance obligation based on whether (i) the customer can benefit from the good or service either on its own or together with other resources that are readily available and (ii) the good or services is separately identifiable from other promises in the contract. The consideration under the arrangement is then allocated to each separate distinct performance obligation based on their respective relative stand-alone selling price. The estimated selling price of each deliverable reflects our best estimate of what the selling price would be if the deliverable was regularly sold by us on a stand-alone basis or using an observable cost plus margin approach if selling price on a stand-alone basis is not available. The consideration allocated to each distinct performance obligation is recognized as revenue when control is transferred for the related goods or services or when the performance obligation has been satisfied. +Other revenues . Other revenues consist primarily of royalty income, funding of research and development efforts and cost reimbursements under a charitable support agreement. Royalties from licensees are based on third-party sales of licensed products and are recorded when the related third-party product sale occurs. Funding and charitable support reimbursements are recorded as the activities are being performed in accordance with the respective agreements. +F-12 +Deferred Revenue +We record deferred revenue when funds are received prior to the recognition of the associated revenue. Deferred revenue as of December 31, 2019 and 2018 includes customer prepayments of $ 1,904 and $ 2,057 , respectively. Deferred revenue as of December 31, 2019 and 2018 also included $ 1,809 and $ 1,464 , respectively, associated with a long-term contract that has variable pricing based on volume. The average price over the life of contract was determined and revenue is recognized at that rate when the product is delivered to the customer. +Financing and Payment . Our payment terms vary by the type and location of our customer and products or services offered. Payment terms differ by jurisdiction and customer but payment is generally required in a term ranging from 30 to 120 days from date of shipment or satisfaction of the performance obligation. +For certain products or services and customer types, we may require payment before the products are delivered or services are rendered to the customer. +Practical expedients and exemptions . Taxes assessed by governmental authorities, such as sales or value-added taxes, are excluded from product revenues. +Sales commissions are expensed when incurred if the amortization period is one year or less. These costs are recorded in sales and marketing expense in the consolidated statements of operations. If the amortization period exceeds one year, we defer the cost of the commission and expense it over the life of the related sales contract. +Revenues by product. The following table represents total net revenues by product line: +Year Ended December 31, +2019 +2018 +2017 +OraQuick® +$ +56,064 +$ +53,851 +$ +60,558 +Oragene® +46,701 +69,798 +67,232 +ORAcollect® +10,651 +6,052 +1,952 +Intercept® +8,105 +7,709 +8,125 +Microbiome laboratory services +6,104 +1,563 +1,223 +Histofreezer® (through August 16, 2019) +5,702 +8,983 +10,312 +OMNIgene® • GUT +5,226 +4,193 +2,072 +Other products +9,520 +13,279 +10,514 +Net product and service revenues +148,073 +165,428 +161,988 +Royalty income +5,116 +9,653 +— +Research and development funding +851 +4,951 +4,387 +Charitable support reimbursement +261 +1,711 +689 +Grant funding +304 +— +— +Other revenues +6,532 +16,315 +5,076 +Net revenues +$ +154,605 +$ +181,743 +$ +167,064 +Revenues by geographic area . The following table represents total net revenues by geographic area, based on the location of the customer: +December 31, +2019 +2018 +2017 +United States +$ +107,279 +$ +136,847 +$ +121,458 +Europe +11,752 +11,062 +11,827 +Other regions +35,574 +33,834 +33,779 +$ +154,605 +$ +181,743 +$ +167,064 +F-13 +Customer and Vendor Concentrations +One of our customers accounted for 19 % and 7 % of our accounts receivable as of December 31, 2019 and 2018, respectively. The same customer accounted for approximately 15 %, 24 % and 25 % of our net consolidated revenues for the year ended December 31, 2019, 2018, and 2017 respectively. +We currently purchase certain products and critical components of our products from sole-supply vendors. If these vendors are unable or unwilling to supply the required components and products, we could be subject to increased costs and substantial delays in the delivery of our products to our customers. Also, our subsidiary, DNAG, uses two third-party suppliers to manufacture its products. Our inability to have a timely supply of any of these components and products could have a material adverse effect on our business, as well as our financial condition and results of operations. +Leases +In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-02, Leases . The standard requires lessees to recognize lease assets and lease liabilities on the balance sheet and requires expanded disclosures about leasing arrangements. We adopted this standard on January 1, 2019 on a modified retrospective basis and have not restated comparative amounts. Also, we elected the practical expedients permitted under the transition guidance, which allows us to carryforward our historical lease classification, our assessment on whether a contract is or contains a lease, and our initial direct costs for any leases that exist prior to adoption of the new standard. Leases with an initial term of 12 months or less are not recognized on the balance sheet and the associated lease payments are included in the consolidated statements of operations on a straight-line basis over the lease term. As a result, on January 1, 2019, we recorded right-of-use assets of $ 4,027 and lease liabilities of $ 4,263 on our consolidated balance sheet . +Business Combinations and Contingent Consideration +Acquired businesses are accounted for using the acquisition method of accounting, which requires that the purchase price be allocated to the net assets acquired at their respective fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Amounts allocated to contingent consideration are recorded to the balance sheet at the date of acquisition based on their relative fair values. The purchase price allocation requires us to make significant estimates and assumptions, especially at the acquisition date, with respect to intangible assets. Although we believe the assumptions and estimates we have made are reasonable, they are based in part on historical experience and information obtained from the management of the acquired companies and are inherently uncertain. +We account for contingent consideration in accordance with applicable guidance provided within the business combination accounting standard. As part of our consideration for the CoreBiome, Novosanis, and Diversigen acquisitions, we are contractually obligated to pay certain consideration resulting from the outcome of future events. Therefore, we are required to update our underlying assumptions each reporting period, based on new developments, and record such contingent consideration liabilities at fair value until the contingency is resolved. Changes in the fair value of the contingent consideration liabilities are recognized each reporting period and included in our consolidated statements of operations. Our estimates of fair value are based on assumptions we believe to be reasonable, but the assumptions are uncertain and involve significant judgment by management. Updates to these assumptions could have a significant impact on our results of operations in any given period and any updates to the fair value of the contingent consideration could differ materially from the previous estimates. +Examples of critical estimates used in valuing certain intangible assets and contingent consideration include: +• +future expected cash flows from sales and acquired developed technologies; +• +the acquired company's trade name and customer relationships as well as assumptions about the period of time the acquired trade name and customer relationships will continue to be used in the combined company's portfolio; +• +the probability of meeting the future events; and +• +discount rates used to determine the present value of estimated future cash flows. +F-14 +Research and Development +Research and development expenses consist of costs incurred in performing research and development activities, including salaries and benefits, facilities expenses, overhead expenses, clinical trial and related clinical manufacturing expenses, contract services and other outside expenses. Research and development costs are charged to expense as incurred. +Advertising Expenses +Advertising costs are charged to expense as incurred. During 2019, 2018, and 2017, we incurred $ 524 , $ 763 , and $ 717 , respectively, in advertising expenses. +Stock-Based Compensation +We account for stock-based compensation to employees and directors using the fair value method. We recognize compensation expense for stock option and restricted stock awards issued to employees and directors on a straight-line basis over the requisite service period of the award. We recognize compensation expense related to performance-based restricted stock units based on assumptions as to what percentage of each performance target will be achieved. We evaluate these target assumptions on a quarterly basis and adjust compensation expense related to these awards, as appropriate. To satisfy the exercise of options, issuance of restricted stock, or redemption of performance-based restricted stock units, we issue new shares rather than purchase shares in the open market. +Income Taxes +We follow the asset and liability method for accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the respective tax basis of assets and liabilities, as well as operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates for the respective taxing jurisdiction that are expected to apply to taxable income in the years in which those temporary differences and operating loss and credit carryforwards are expected to be recovered, settled or utilized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. +We assess the realizability of our net deferred tax assets on a quarterly basis. If, after considering all relevant positive and negative evidence, it is more likely than not that some portion or all of the net deferred tax assets will not be realized, we reduce our net deferred tax assets by a valuation allowance. The realization of the net deferred tax assets is dependent on several factors, including the generation of sufficient taxable income prior to the expiration of our net operating loss carryforwards. +Foreign Currency Translation +The assets and liabilities of our foreign operations are translated into U.S. dollars at current exchange rates as of the balance sheet date, and revenues and expenses are translated at average exchange rates for the period. Resulting translation adjustments are reflected in accumulated other comprehensive loss, which is a separate component of stockholders’ equity. +Transaction gains and losses resulting from exchange rate changes on transactions denominated in currencies other than functional currency are included in our consolidated statements of income in the period in which the change occurs. Net foreign exchange gains (losses) resulting from foreign currency transactions that are included in other income (expense) in our consolidated statements of income were $( 1,339 ), $ 831 , and $( 1,442 ) for the years ended December 31, 2019, 2018, and 2017, respectively. +Earnings Per Share +Basic earnings per share is computed by dividing net income by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share is computed in a manner similar to basic earnings per share except that the weighted-average number of shares outstanding is increased to include incremental shares from the assumed vesting or exercise of dilutive securities, such as common stock options, unvested restricted stock or performance stock units, unless the impact is antidilutive. The number of incremental shares is calculated by assuming that outstanding stock options were exercised and unvested restricted shares and performance stock units were vested, and the proceeds from such exercises or vesting were used to acquire shares of common stock at the average market price during the reporting period. +F-15 +The computations of basic and diluted earnings per share are as follows: +Year ended December 31, +2019 +2018 +2017 +Net income +$ +16,656 +$ +20,396 +$ +30,948 +Weighted average shares of common stock outstanding: +Basic +61,675 +61,112 +59,050 +Dilutive effect of stock options, restricted stock, and +performance stock units +495 +1,420 +1,974 +Diluted +62,170 +62,532 +61,024 +Earnings per share: +Basic +$ +0.27 +$ +0.33 +$ +0.52 +Diluted +$ +0.27 +$ +0.33 +$ +0.51 +For the years ended December 31, 2019, 2018, and 2017, outstanding common stock options, unvested restricted stock, and unvested performance stock units representing 768 , 291 , and 180 shares, respectively, were excluded from the computation of diluted earnings per share as their inclusion would have been anti-dilutive. +Accumulated Other Comprehensive Loss +We classify items of other comprehensive income (loss) by their nature and disclose the accumulated balance of other comprehensive loss separately from accumulated deficit and additional paid-in capital in the stockholders’ equity section of our consolidated balance sheets. +We have defined the Canadian dollar as the functional currency of our Canadian subsidiary, DNAG, and we have defined the Euro as the functional currency of our Belgian subsidiary, Novosanis. The results of operations are translated into U.S. dollars, which is the reporting currency of the Company. Accumulated other comprehensive loss at December 31, 2019 consists of $ 12,022 of currency translation adjustments and $ 114 of net unrealized losses on marketable securities, which represents the fair market value adjustment for our investments portfolio. Accumulated other comprehensive loss at December 31, 2018 consists of $ 17,789 of currency translation adjustments and $ 917 of net unrealized losses on marketable securities. +Fair Value of Financial Instruments +As of December 31, 2019 and 2018, the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate their respective fair values based on their short-term nature. +Fair value measurements of all financial assets and liabilities that are being measured and reported on a fair value basis are required to be classified and disclosed in one of the following three categories: +Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; +Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and +Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). +All of our available-for-sale debt securities are measured as Level 2 instruments as of December 31, 2019 and 2018. +Included in cash and cash equivalents at December 31, 2019 and 2018, was $ 1,624 and $ 21,631 invested in government money market funds. These funds have investments in government securities and are measured as Level 1 instruments. +F-16 +We offer a nonqualified deferred compensation plan for certain eligible employees and members of our Board of Directors. The assets of the plan are held in the name of the Company at a third-party financial institution. Separate accounts are maintained for each participant to reflect the amounts deferred by the participant and all earnings and losses on those deferred amounts. The assets of the plan are held in mutual funds and Company stock. The fair value of the plan assets as of December 31, 2019 and 2018 was $ 3,519 and $ 3,884 , respectively, and was calculated using the quoted market prices of the assets as of those dates. All investments in the plan are classified as trading securities and measured as Level 1 instruments. The fair value of plan assets is included in both current assets and other noncurrent assets with the same amounts included in accrued expenses and other noncurrent liabilities in the accompanying consolidated balance sheets. +Recent Accounting Pronouncements +In June 2016, the FASB issued guidance on the measurement of credit losses, which requires measurement and recognition of expected credit losses for financial assets, including trade receivables and capital lease receivables, held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The method to determine a loss is different from the existing guidance, which requires a credit loss to be recognized when it is probable. The guidance is effective beginning in fiscal year 2020, with early adoption permitted beginning in fiscal year 2019. We have determined that this new guidance will not have a material impact on our consolidated financial statements. +In February 2018, the FASB issued guidance allowing a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act. The guidance is effective in fiscal year 2020, with early adoption permitted, including adoption in an interim period. If elected, the reclassification can be applied in either the period of adoption or retrospectively to the period of the enactment of the U.S. Tax Cuts and Jobs Act (i.e., our first quarter of fiscal year 2018). We have determined that this new guidance will not have a material impact on our consolidated financial statements. +In August 2018, the FASB issued guidance related to fair value measurement disclosures. This guidance removes the requirement to disclose the amount of and reasons for transfers between Levels 1 and 2 of the fair value hierarchy, the policy for determining that a transfer has occurred, and valuation processes for Level 3 fair value measurements. Additionally, this guidance modifies the disclosures related to the measurement uncertainty for recurring Level 3 fair value measurements (by removing the requirement to disclose sensitivity to future changes) and the timing of liquidation of investee assets (by removing the timing requirement in certain instances). The guidance also requires new disclosures for Level 3 financial assets and liabilities, including the amount and location of unrealized gains and losses recognized in other comprehensive income/(loss) and additional information related to significant unobservable inputs used in determining Level 3 fair value measurements. This guidance is effective beginning in fiscal year 2020. We have determined that this new guidance will not have a material impact on our consolidated financial statements. +In August 2018, the FASB issued guidance related to accounting for implementation costs incurred in hosted cloud computing service arrangements. Under the new guidance, implementation costs incurred in a hosting arrangement that is a service contract should be expensed or capitalized based on the nature of the costs and the project stage during which such costs are incurred. If the implementation costs qualify for capitalization, they must be amortized over the term of the hosting arrangement and assessed for impairment. Companies must disclose the nature of any hosted cloud computing service arrangements. This guidance also provides guidance for balance sheet and income statement presentation of capitalized implementation costs and statement of cash flows presentation for the related payments. This guidance will be effective beginning in the first quarter of our fiscal year 2020. This guidance may be adopted either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We will prospectively adopt this guidance and have determined that it will not have a material impact on our consolidated financial statements. +In December 2019, the FASB issued guidance that simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in Accounting Standards Codification (“ASC”) 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The standard also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. This guidance is effective beginning in fiscal year 2020, with early adoption permitted beginning in fiscal year 2019. We have early-adopted this guidance and determined that this new guidance does not have a material impact on our consolidated financial statements. +F-17 +3. BUSINESS COMBINATIONS +CoreBiome and Novosanis +On January 4, 2019, the Company acquired all of the outstanding stock of CoreBiome, pursuant to the terms of a merger agreement, dated January 3, 2019. Also on January 4, 2019, the Company, through a wholly-owned subsidiary, acquired all of the outstanding stock of Novosanis, pursuant to a share purchase agreement, dated January 3, 2019. We began operating these entities as of the January 4, 2019 closing date. The aggregate purchase price for both of these transactions was $ 13,320 adjusted for certain transaction costs, indebtedness, and holdback amounts, and was funded with cash on hand. A portion of the purchase price was deposited into escrow accounts for a limited period after closing, in order to secure the potential payment of certain indemnification obligations of the selling stockholders under each agreement noted above. +During the year ended December 31, 2019, we incurred a total of $ 639 of acquisition-related costs in connection with these acquisitions, including success-based investment banking fees and accounting, legal and other professional fees, related to both acquisitions, all of which were expensed and reported as a component of general and administrative expenses in the consolidated statement of income. +Pursuant to our acquisition agreements, we were to pay up to an additional $ 32,400 of contingent consideration over the next three years based on the achievement of certain performance criteria as defined under the agreements, including generating certain revenue dollars, the achievement of a large customer contract, and the development of certain new technology. The Company, with the assistance of an independent valuation specialist, utilized a Monte Carlo simulation to determine the estimated acquisition-date fair value of the acquisition-related contingent consideration of $ 4,350 . The simulation calculates the probability-weighted payments based on our assessment of the likelihood that the benchmarks will be achieved. The probability-weighted payments were then discounted using a discount rate based on an internal rate of return analysis using the probability-weighted cash flows. The fair value measurement was based on significant inputs, including revenue forecasts, not observable in the market and thus represents a Level 3 measurement within the fair value hierarchy. The fair value of the contingent consideration obligation changed from $ 4,350 as of the acquisition date to $ 3,612 as of December 31, 2019. This change is a result of changes in our estimated revenue forecasts and an amendment to one of the agreements, entered into in October 2019, in which management agreed to settle the contingent consideration associated with one of the acquisition’s 2019 results for $ 3,500 . As of December 31, 2019, we may pay up to an additional $ 27,400 of contingent consideration over the next two years . +The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition date: +Assets Acquired +Accounts receivable +$ +791 +Inventories +310 +Other current assets +82 +Property, plant, and equipment, net +414 +Other assets +5 +Acquired intangible assets +8,400 +Goodwill +10,368 +Total assets acquired +20,370 +Liabilities Assumed +Current liabilities +1,180 +Notes payable, short-term +730 +Deferred tax liability +819 +Other long-term liabilities +74 +Total liabilities assumed +2,803 +Net Assets Acquired +17,567 +Estimated fair value of contingent consideration +( 4,350 +) +Net Cash Paid (net of cash acquired of $ 103 ) +$ +13,217 +The purchase price was allocated to the tangible assets and identifiable intangible assets acquired and liabilities assumed based on their acquisition-date estimate fair values. The identifiable intangible assets principally included developed technology, customer relationships, and tradenames, all of which are subject to amortization on a straight-line basis and are being amortized over estimated useful lives as summarized below: +F-18 +Estimated Useful +Description +Life (in yrs) +Amount +Developed Technology +10 +$ +5,000 +Customer relationships +10 +2,200 +Tradenames +8.34 +1,200 +Total acquired intangibles +$ +8,400 +The Company, with the assistance of an independent valuation specialist, assessed the fair value of the assets of CoreBiome and Novosanis. The income approach was used to value the acquired intangibles and the fair value measurements were primarily based on significant inputs that are not observable in the market and are considered Level 3 fair value measurements. The income approach estimates fair value for an asset based on the present value of cash flows projected to be generated by the asset. Projected cash flows are discounted at a required rate of return that reflects the relative risk of achieving the cash flows and the time value of money. +The useful lives of the intangible assets were estimated based on the expected future economic benefit of the assets and are being amortized over the estimated useful life in proportion to the economic benefits consumed using the straight-line method. +The amortization of intangible assets is not deductible for income tax purposes. +Goodwill is calculated as the difference between the acquisition date fair value of the consideration transferred and the fair value of the net assets acquired, and represents the future economic benefits that we expect to achieve as a result of the acquisition. We believe the goodwill related to the acquisitions was a result of providing us a complementary service and product offering that will enable us to leverage those services and products with existing and new customers. The goodwill is not deductible for income tax purposes. All of the goodwill identified above has been allocated to our DNAG segment. +Revenues from CoreBiome primarily consist of microbiome laboratory services that utilize optimal analytical algorithms to deliver speed and scalability in the lab with precise analytics. Revenues from Novosanis primarily consist of the sale of its Colli-Pee collection device which was designed for the standard collection of first-void urine used in the liquid biopsy and sexually transmitted infection screening market. Effective as of January 4, 2019, the financial results of CoreBiome and Novosanis are included in our DNAG segment. For the year ended December 31, 2019, consolidated net revenues include combined revenues associated with the CoreBiome and Novosanis business of $ 5,152 . Consolidated results from operations for the year ended December 31, 2019 included a net loss of $ 2,450 generated from the combined companies since the acquisition date. +Diversigen +On November 8, 2019, the Company acquired all of the outstanding stock of Diversigen, Inc. (“Diversigen”), pursuant to the terms of a merger agreement. We began operating this entity as of the November 8, 2019 closing date. +The aggregate purchase price for this transaction was $ 12,000 , adjusted for certain transaction costs, indebtedness, and holdback amounts, and was funded with cash on hand. A portion of the purchase price was deposited into an escrow account for a limited period after closing, pursuant to indemnification obligations under the merger agreement noted above. +During the year ended December 31, 2019, we incurred a total of $ 1,198 of acquisition related costs, including investment banking fees and accounting, legal and other professional fees, all of which were expensed and reported as a component of general and administrative expenses in the consolidated statement of income for the year ended December 31, 2019. +Pursuant to our acquisition agreements, we were to pay up to an additional $ 1,500 of contingent consideration in 2020 based on the achievement of certain 2019 revenue metrics as defined under the agreements. The estimated acquisition-date fair value of the acquisition-related contingent consideration was $ 0 . The fair value of the contingent consideration obligation of $ 0 is a result of not achieving the defined revenue metrics. +F-19 +The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed as of the acquisition date: +Assets Acquired +Accounts receivable +$ +1,234 +Other current assets +45 +Property, plant, and equipment, net +1,916 +Acquired intangible assets +3,560 +Goodwill +6,443 +Total assets acquired +13,198 +Liabilities Assumed +Current liabilities +1,123 +Deferred tax liability +598 +Other long-term liabilities +893 +Total liabilities assumed +2,614 +Net Assets Acquired +10,584 +Estimated fair value of contingent consideration +- +Net Cash Paid (net of cash acquired of $ 479 ) +$ +10,584 +The purchase price was allocated to the tangible assets and identifiable intangible assets acquired and liabilities assumed based on their acquisition-date estimate fair values. The identifiable intangible assets included customer relationships and tradenames, all of which are subject to amortization on a straight-line basis and are being amortized over estimated useful lives as summarized below: +Estimated Useful +Description +Life (in yrs) +Amount +Customer relationships +10 +2,900 +Tradenames +9 +660 +Total acquired intangibles +$ +3,560 +The Company, with the assistance of an independent valuation specialist, assessed the fair value of the assets of Diversigen. The income approach was used to value the acquired intangibles and the fair value measurements were primarily based on significant inputs that are not observable in the market and are considered Level 3 fair value measurements. The income approach estimates fair value for an asset based on the present value of cash flows projected to be generated by the asset. Projected cash flows are discounted at a required rate of return that reflects the relative risk of achieving the cash flows and the time value of money. +The useful lives of the intangible assets were estimated based on the expected future economic benefit of the assets and are being amortized over the estimated useful life in proportion to the economic benefits consumed using the straight-line method. +The amortization of intangible assets is not deductible for income tax purposes. +Goodwill is calculated as the difference between the acquisition date fair value of the consideration transferred and the fair value of the net assets acquired, and represents the future economic benefits that we expect to achieve as a result of the acquisition. We believe the goodwill related to the acquisitions was a result of providing us a complementary service and product offering that will enable us to leverage those services and products with existing and new customers. The goodwill is not deductible for income tax purposes. All of the goodwill identified above has been allocated to our DNAG segment. +We continue to evaluate the fair value of certain assets acquired and liabilities assumed. Additional information, which existed as of the acquisition date, but was at that time unknown to us, may become known during the remainder of the measurement period. Changes to amounts recorded as a result of the final determination may result in a corresponding adjustment to these assets and liabilities, including goodwill. The determination of the estimated fair values of all assets acquired is expected to be completed within one year from the date of acquisition. +Revenues from Diversigen primarily consist of microbiome laboratory services that provide metagenomics sequencing, bioinformatics and statistical analysis for the study of the microbiome. Effective as of November 8, 2019, the financial results of Diversigen are included in our DNAG segment. For the year ended December 31, 2019, consolidated net revenues include revenues associated with +F-20 +the Diversigen business of $ 1,046 , and consolidated results from operations include a net loss of $ 47 generated since the acquisition date. +Unaudited Pro Forma Financial Information +The unaudited pro forma results presented below include the results of the CoreBiome, Diversigen, and Novosanis acquisitions as if they had been consummated as of January 1, 2017. The unaudited pro forma results include the amortization associated with acquired intangible assets and the estimated tax effect of adjustments to income before income taxes but do not include changes in the fair value of our contingent consideration obligations. Material nonrecurring charges, directly attributable to the transactions, including direct acquisition costs, are also excluded. In addition, the unaudited pro forma results do not include any expected benefits of the acquisitions. Accordingly, the unaudited pro forma results are not necessarily indicative of either future results of operations or results that might have been achieved had the acquisitions been consummated as of January 1, 2017. +Year Ended December 31, +2019 +2018 +2017 +Revenue +$ +158,576 +$ +190,487 +$ +173,554 +Net income +16,806 +19,448 +27,436 +Net income per share, basic +0.27 +0.32 +0.46 +Net income per share, diluted +0.27 +0.31 +0.45 +4. SALE OF CRYOSURGICAL BUSINESS +On August 16, 2019, we sold all rights and title to the assets necessary to operate our cryosurgical systems line of business to +a third party for $ 12,000 . This business consisted of medical devices used for the removal of benign skin lesions by cryosurgery or freezing. The products were sold in both the professional and OTC markets in North America, Europe, Central and South America and Australia. We also entered into a transition services agreement with CryoConcepts in which both parties agreed to provide certain transition services beginning after the closing. The Company recorded a gain on sale of business of $ 10,149 reflected in our statement of income for the year ended December 31, 2019. The gain includes the $ 12,000 of proceeds net of the fair value of the assets sold, which consisted entirely of inventory and fully-depreciated fixed assets, the legal fees associated with the transaction, and a value attributed to the transition services. +5 . +INVENTORIES: +December 31, +2019 +2018 +Raw materials +$ +14,168 +$ +14,092 +Work in process +643 +544 +Finished goods +8,344 +8,252 +$ +23,155 +$ +22,888 +F-21 +6 . +PROPERTY, PLANT AND EQUIPMENT: +December 31, +2019 +2018 +Land +$ +1,118 +$ +1,118 +Buildings and improvements +23,231 +22,480 +Machinery and equipment +33,568 +29,017 +Computer equipment and software +11,590 +9,632 +Furniture and fixtures +2,791 +2,681 +Construction in progress +4,923 +2,168 +77,221 +67,096 +Less accumulated depreciation +( 46,882 +) +( 42,797 +) +$ +30,339 +$ +24,299 +Depreciation expense was $ 4,421 , $ 3,828 , and $ 3,434 for 2019, 2018, and 2017, respectively. +7 . +GOODWILL AND OTHER INTANGIBLE ASSETS: +The changes in goodwill are as follows: +December 31, +2019 +2018 +Balance as of January 1 +18,521 +20,083 +Goodwill acquired during the year +16,811 +— +Change related to foreign currency translation +869 +( 1,562 +) +Balance as of December 31 +$ +36,201 +$ +18,521 +Intangible assets consist of the following: +December 31, 2019 +Amortization Period (Years) +Gross +Accumulated Amortization +Net +Customer relationships +10 +$ +14,731 +$ +( 8,054 +) +$ +6,677 +Patents and product rights +10 +5,400 +( 5,158 +) +242 +Developed technology +7-10 +12,410 +( 7,982 +) +4,428 +Tradename +5-15 +5,553 +( 2,226 +) +3,327 +$ +38,094 +$ +( 23,420 +) +$ +14,674 +December 31, 2018 +Amortization +Period (Years) +Gross +Accumulated +Amortization +Net +Customer relationships +10 +$ +9,186 +$ +( 6,532 +) +$ +2,654 +Patents and product rights +10 +5,400 +( 4,708 +) +692 +Developed technology +7 +7,135 +( 7,135 +) +- +Tradename +15 +3,521 +( 1,730 +) +1,791 +$ +25,242 +$ +( 20,105 +) +$ +5,137 +Amortization expense for 2019, 2018, and 2017 was $ 2,522 , $ 2,623 , and $ 2,641 , respectively. +F-22 +Amortization expense for each of the five succeeding fiscal years and beyond is estimated as follows: +2020 +2,619 +2021 +2,375 +2022 +1,470 +2023 +1,470 +2024 +1,430 +Beyond +5,310 +$ +14,674 +8 . +ACCRUED EXPENSES: +December 31, +2019 +2018 +Payroll and related benefits +$ +6,088 +$ +8,926 +Professional fees +2,769 +1,541 +Income taxes payable +— +1,447 +Other +5,431 +1,947 +$ +14,288 +$ +13,861 +9 . +CREDIT FACILITY: +On March 29, 2019, we terminated our credit agreement with a commercial bank which was entered into on September 30, 2016 and had a maturity date of September 30, 2019. There were no borrowings under the credit agreement during 2019, 2018, or 2017. +10. LEASES: +In February 2016, the FASB issued ASU No. 2016-02, Leases . The standard requires lessees to recognize lease assets and lease liabilities on the balance sheet and requires expanded disclosures about leasing arrangements. We adopted this standard on January 1, 2019 on a modified retrospective basis and will not restate comparative amounts. +We determine whether an arrangement is a lease at inception. We have operating and finance leases for corporate offices, warehouse space and equipment (including vehicles). As of December 31, 2019, we are the lessee in all agreements. Our leases have remaining lease terms of 1 to 7 years , some of which include options to extend the leases based on agreed upon terms, and some of which include options to terminate the leases within 1 year. +As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at the lease commencement date in determining the present value of lease payments. +We have lease agreements that contain both lease and non-lease components (e.g., common-area maintenance). For these agreements, we account for lease components separate from non-lease components. +The components of lease expense are as follows: +Year ended +December 31, 2019 +Operating Lease Cost +$ +964 +Finance Lease Cost +Amortization of right-of use assets +410 +Interest on lease liabilities +36 +Total Finance Lease Cost +$ +446 +Lease cost for the years ended December 31, 2018 and 2017 was $ 1,461 and $ 852 , respectively. +F-23 +Supplemental cash flow information related to leases is as follows: +Year ended +December 31, 2019 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases +$ +937 +Operating cash flows from financing leases +33 +Financing cash flows from financing leases +442 +Non-cash activity +Right-of-use assets obtained in exchange for operating lease obligations +1,829 +Right-of-use assets obtained in exchange for finance lease obligations +2,069 +Right of use assets obtained include those assets acquired and entered into during 2019. +Supplemental balance sheet information related to leases is as follows: +December 31, 2019 +Operating Leases +Right-of-use assets +$ +4,996 +Current lease liabilities +1,032 +Non-current lease liabilities +4,206 +Total operating lease liabilities +$ +5,238 +Finance Leases +Right-of-use assets +$ +1,951 +Current lease liabilities +613 +Non-current lease liabilities +1,372 +Total finance lease liabilities +$ +1,985 +Weighted Average Remaining Lease Term +Weighted-average remaining lease term—operating leases +5.21 +Weighted-average remaining lease term—finance leases +3.45 +Weighted Average Discount Rate +Weighted-average discount rate—operating leases +4.31 +% +Weighted-average discount rate—finance leases +4.40 +% +As of December 31, 2019, minimum lease payments by period are expected to be as follows: +Finance +Operating +2020 +685 +1,273 +2021 +556 +1,214 +2022 +555 +1,194 +2023 +325 +759 +2024 +17 +777 +Thereafter +4 +760 +Total Minimum Lease Payments +2,142 +5,977 +Less: imputed interest +( 157 +) +( 739 +) +Present Value of Lease Liabilities +$ +1,985 +$ +5,238 +F-24 +As of December 31, 2018, minimum lease payments under non-cancelable operating leases by period were expected to be as follows: +2019 +$ +903 +2020 +902 +2021 +877 +2022 +850 +2023 +506 +Thereafter +737 +$ +4,775 +11 . +INCOME TAXES: +Income before income tax expense consists of the following: +Years Ended December 31, +2019 +2018 +2017 +United States +$ +3,106 +$ +( 11,728 +) +$ +2,270 +Foreign +18,225 +43,444 +38,762 +$ +21,331 +$ +31,716 +$ +41,032 +The components of income tax expense are as follows: +Years Ended December 31, +2019 +2018 +2017 +Current +Federal +$ +— +$ +— +$ +— +State +1,033 +155 +— +Foreign +5,099 +12,084 +10,733 +6,132 +12,239 +10,733 +Deferred +Federal +3,568 +9,200 +10,297 +State +125 +1,011 +( 827 +) +Foreign +( 697 +) +( 919 +) +( 649 +) +2,996 +9,292 +8,821 +Decrease in valuation allowance +( 4,453 +) +( 10,211 +) +( 9,470 +) +( 1,457 +) +( 919 +) +( 649 +) +Total income tax expense +$ +4,675 +$ +11,320 +$ +10,084 +For the years ended December 31, 2019, 2018, and 2017 we recorded foreign income tax expense of $ 4,607 , $ 11,165 , and $ 10,084 , respectively. +The Tax Cuts and Jobs Act +On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Tax Act”) that instituted fundamental changes to the taxation on multinational corporations. Although the Tax Act is generally effective January 1, 2018, U.S. generally accepted accounting principles requires recognition of the tax effects of new legislation during the reporting period that includes the enactment date, which was December 22, 2017. Among the numerous provisions, the Tax Act includes three provisions in particular which require consideration for financial reporting: a permanent reduction in the corporate tax rate to 21 %, a one-time tax on undistributed foreign earnings, and a new U.S. tax on global intangible low taxed income (“GILTI”) which is a tax on certain earnings of foreign affiliates. +The reduction in the U.S. corporate tax rate to 21 % became effective in 2018. This change resulted in a re-measurement of our net deferred tax balance at the end of 2017 with no net financial statement impact due to a comparable decrease in our deferred tax valuation allowance. +F-25 +The one-time tax on undistributed and previously untaxed post-1986 foreign earnings and profits (E&P) of foreign affiliates owned by U.S. shareholders as of December 31, 2017 was analyzed for our Canadian subsidiary. For the 2017 federal tax return filed during 2018 our U.S. federal taxable loss exceeded and offset the provisional mandatory repatriation net inclusion and as such, no additional taxes w ere due as a result of the deemed repatriation of these foreign earnings. +In addition, the Tax Act also included changes to the taxation of foreign earnings by implementing a dividend exemption system, expansion of the current anti-deferral rules, a minimum tax on low-taxed foreign earnings and new measures to deter base erosion and promote U.S. production. The Tax Act also included repeal of the corporate alternative minimum tax, expensing of capital investment, changes to the Federal net operating loss (“NOL”) utilization and carryforward rules, and limitations of the deduction for interest expense and certain employee compensation. +As a result of the complex impact of the Tax Act, the SEC provided guidance under Staff Accounting Bulletin No. 118 (“SAB 118”) that allowed the Company to record provisional amounts as of December 31, 2017 for the impact of the Tax Act, provided that the provisional amounts could be reasonably determined and with the requirement that the final accounting be completed in a period not to exceed one year from the date of enactment. As of December 31, 2018, the Company has completed the accounting for the tax effects of the Tax Act, and therefore, has recorded final amounts which include: +(a) +The impact of the one-time transition tax on existing net operating loss and foreign tax credit carryforwards generated, as well as the related offsetting valuation allowances. The final one-time transitioned income reported on the 2017 federal tax return filed in 2018 was $ 17,724 . This amount decreased both the net operating loss carryforward as well as the corresponding valuation allowance. Based on updated guidance, in 2018 the Company elected to deduct foreign taxes and therefore did no t generate foreign tax credits. As such the deferred tax asset recorded as of December 31, 2017 associated with foreign tax credits was reversed in 2018. +(b) +The valuation allowance for the Company’s deferred tax assets as of December 31, 2017, was primarily dependent on forecasted future taxable income in the U.S. and Canada and was impacted by the provisions of the Tax Act. The primary impact of the Tax Act was the lowering of the statutory rate to 21 %. This lowered the deferred tax assets and corresponding valuation allowance by $ 11,273 . +The Tax Act imposed a U.S. tax on GILTI that is earned by certain foreign affiliates owned by a U.S. shareholder effective in 2018. GILTI is generally intended to impose tax on the earnings of a foreign corporation that are deemed to exceed a certain threshold return relative to the underlying tangible property. The GILTI computation for 2018 was completed and is reflected in the 2018 income tax provision. The Company has made a policy election related to its treatment of GILTI and will treat it as a current period expense in the reporting period in which the tax is incurred. +A reconciliation of the statutory United States federal income tax rate to our effective tax rate for each of the years ended December 31, 2019, 2018, and 2017 is as follows: +2019 +2018 +2017 +Statutory U.S. federal income tax rate +21.0 +% +21.0 +% +34.0 +% +Deemed repatriation tax +— +10.9 +7.8 +GILTI tax +16.9 +22.2 +— +Statutory rate change, deferred tax impact +— +— +29.4 +Nondeductible executive compensation +0.4 +4.8 +— +Impact of share-based payment awards +( 5.3 +) +0.6 +( 16.0 +) +Tax effect of foreign items +4.5 +6.8 +( 8.3 +) +State income taxes, net of federal benefit +4.0 +2.8 +( 1.1 +) +Nondeductible transaction costs +1.6 +— +— +Nondeductible expenses and other +( 0.7 +) +( 1.2 +) +1.9 +Change in valuation allowance, federal and state +( 20.5 +) +( 32.2 +) +( 23.1 +) +Effective tax rate +21.9 +% +35.7 +% +24.6 +% +F-26 +Deferred income taxes reflect the tax effects of temporary differences between the basis of assets and liabilities recognized for financial reporting purposes and tax purposes, and net operating loss and tax credit carryforwards. Significant components of our deferred tax assets (liabilities) as of December 31, 2019 and 2018 are as follows: +2019 +2018 +Deferred tax assets (liabilities): +Net operating loss carryforwards +$ +9,897 +$ +10,812 +Inventories +2,002 +1,005 +Capitalized research and development costs +1,183 +1,697 +Accruals and reserves currently not deductible +2,272 +3,767 +Acquired intangible assets +( 3,525 +) +( 1,153 +) +Depreciation and amortization +( 1,999 +) +( 1,082 +) +Stock-based compensation +1,777 +1,248 +Tax credit carryforwards +2,055 +1,819 +Net deferred tax asset +13,662 +18,113 +Valuation allowance +( 14,561 +) +( 19,014 +) +Net deferred tax liability +$ +( 899 +) +$ +( 901 +) +In assessing the realizability of our deferred tax asset, we consider all relevant positive and negative evidence in determining whether it is more likely than not that some portion or all of the deferred income tax assets will not be realized. The realization of the gross deferred tax assets is dependent upon several factors, including the generation of sufficient taxable income prior to the expiration of the NOL carryforwards. In 2008, we established a full valuation allowance against our U.S. deferred tax asset, and management believes the full valuation allowance is still appropriate as of December 31, 2019 and 2018 since the facts and circumstances necessitating the allowance have not changed. As a result, no U.S. federal income tax benefit was recorded for the years ended December 31, 2019, 2018, or 2017. +Our Federal NOL carryforwards expire as follows: +Year of Expiration +NOLs +2030 - 2034 +$ +22,653 +2035 - 2037 +$ +12,055 +Non-Expiring +1,709 +$ +36,417 +The accounting guidance under ASU 2016-09 allows for the recognition of excess tax benefits associated with stock-based compensation awards regardless of whether the deduction reduces taxes payable. On January 1, 2017, we recorded a cumulative adjustment to retained earnings of $ 3,391 to recognize the increase in our net operating loss carryforwards from the cumulative excess tax benefits not recognized in periods prior to January 1, 2017. A corresponding $ 3,391 increase to our valuation allowance associated with this tax benefit was also recorded to retained earnings thereby resulting in no impact to retained earnings. +The Tax Reform Act of 1986 contains provisions under Internal Revenue Code (“IRC”) Section 382 that limit the annual amount of federal and state NOL carryforwards that can be used in any given year in the event a significant change in ownership. We do not believe that there is a Section 382 limitation that will impair our future ability to utilize NOLs to offset our future taxable income. We continue to review ownership changes on an annual basis and we do not believe we have had a subsequent ownership change that would impact the NOLs. +Effective January 1, 2018, there is a transition to a participation exemption system whereby distributions from foreign subsidiaries to U.S. shareholders are generally exempt from taxation. Our intention is to continue to permanently reinvest the historical undistributed earnings of our foreign subsidiary to the extent that we will not incur any additional tax expense associated with foreign withholding or other local tax expense on the future cash transfers. As such, deferred taxes have not been recorded on the unremitted earnings of the foreign subsidiary. +F-27 +As of December 31, 2019, our gross unrecognized tax benefits totaled $ 1,308 , and based upon the valuation allowance for our U.S. operations, the recognition of any tax benefit would not impact our effective tax rate. We record interest and penalties related to unrecognized tax benefits as a component of income tax expense. Interest and penalties were immaterial in 2019, 2018 and 2017. As a result of our net operating loss carryforward position, we are subject to audit by the Internal Revenue Service since our inception, as well as by several state jurisdictions for the years ended September 30, 1998 through December 31, 2019. +A reconciliation of our unrecognized tax benefits is as follows: +2019 +2018 +2017 +Balance as of January 1 +$ +1,676 +$ +1,663 +$ +2,084 +Additions for tax positions of prior periods +4 +44 +- +Reductions for tax positions of prior periods +( 372 +) +( 31 +) +( 421 +) +Balance as of December 31 +$ +1,308 +$ +1,676 +$ +1,663 +1 2 . +STOCKHOLDERS’ EQUITY: +Stock-Based Awards +We grant stock-based awards under the OraSure Technologies, Inc. Stock Award Plan, as amended (the “Stock Plan”). The Stock Plan permits stock-based awards to employees, outside directors and consultants or other third-party advisors. Awards which may be granted under the Stock Plan include qualified incentive stock options, nonqualified stock options, stock appreciation rights, restricted awards, performance awards and other stock-based awards. +As of December 31, 2019, 2,534 shares were available for future grants under the Stock Plan. +Under the terms of the Stock Plan, nonqualified stock options may be granted to eligible employees, including our officers at a price not less than 75 percent of the fair market value of a share of common stock on the date of grant. The option term and vesting schedule of such awards may be either unlimited or have a specified period in which to vest and be exercised. To date, options generally have been granted with ten-year exercise periods and an exercise price not less than the fair market value on the date of grant. Options generally vest over four years , with one quarter of the options vesting one year after grant and the remainder vesting on a monthly basis over the next three years. +The fair value of each stock option was estimated on the date of the grant using the Black-Scholes option-pricing model using the following weighted-average assumptions: +Years Ended December 31, +Black-Scholes Option Valuation Assumptions +2019 +2018 +2017 +Risk-free interest rate (1) +2.52 +% +2.60 +% +2.22 +% +Expected dividend yield +— +— +— +Expected stock price volatility (2) +41 +% +43 +% +43 +% +Expected life of stock options (in years) (2) +5 +6 +7 +(1) +Based on the constant maturity interest rate of U.S. Treasury securities whose term is consistent with the expected life of our stock options. +(2) +Based upon historical experience. +The weighted-average grant date fair value of stock options granted during the years ended December 31, 2019, 2018 and 2017 was $ 5.19 , $ 9.15 and $ 4.71 , respectively. +Compensation expense recognized in the financial statements related to stock options was as follows: +Years Ended December 31, +2019 +2018 +2017 +Total compensation cost during the year +$ +1,161 +$ +2,163 +$ +2,045 +Amounts capitalized into inventory during the year +( 343 +) +( 420 +) +( 371 +) +Amounts recognized in cost of products sold for amounts previously capitalized +405 +396 +276 +Amounts charged against income +$ +1,223 +$ +2,139 +$ +1,950 +F-28 +The aggregate intrinsic value of options exercised during the years ended December 31, 2019, 2018, and 2017 (the amount by which the market price of the stock on the date of exercise exceeded the exercise price) was $ 92 , $ 2,314 , and $ 35,631 , respectively. +The following table summarizes the stock option activity under the Stock Plan: +Options +Weighted-Average +Exercise Price Per +Share +Weighted-Average +Remaining +Contractual Term +(in years) +Aggregate +Intrinsic +Value +Outstanding on January 1, 2019 +1,083 +10.19 +Granted +215 +12.71 +Exercised +( 27 +) +7.17 +Expired +( 41 +) +8.68 +Forfeited +( 37 +) +13.05 +Outstanding on December 31, 2019 +1,193 +$ +10.68 +5.89 +$ +651 +Vested or expected to vest as of December 31, 2019 +1,193 +$ +10.68 +5.89 +$ +651 +Exercisable on December 31, 2019 +896 +$ +9.79 +4.99 +$ +630 +As of December 31, 2019, there was $ 1,423 of unrecognized compensation expense related to unvested option awards that is expected to be recognized over a weighted-average period of 2.5 years. +Net cash proceeds from the exercise of stock options were $ 196 , $ 1,701 and $ 31,675 for the years ended December 31, 2019, 2018, and 2017, respectively. As a result of our net operating loss carryforward position, no actual income tax benefit was realized from stock option exercises for these periods. +The following table summarizes information about stock options outstanding as of December 31, 2019: +Options outstanding +Options exercisable +Range of exercise prices +Number +Outstanding +Weighted- +Average +Remaining +Contractual +Term +(in years) +Weighted- +Average +Exercise +Price Per +Share +Number +Exercisable +Weighted- +Average +Exercise +Price Per +Share +$5.37 - $8.24 +371 +4.6 +$ +6.16 +352 +$ +6.13 +$8.87 - $14.95 +657 +6.1 +10.82 +432 +10.08 +$16.80 - $21.89 +165 +8.1 +20.30 +112 +20.15 +1,193 +5.9 +$ +10.68 +896 +$ +9.79 +The Stock Plan also permits us to grant restricted shares and restricted units of our common stock to eligible employees, including officers, and our outside directors. Generally, these shares or units are nontransferable until vested and are subject to vesting requirements and/or forfeiture, as determined by our Compensation Committee or Board of Directors. The market value of these shares and units at the date of grant is recognized on a straight-line basis over the period during which the restrictions lapse. Compensation cost of $ 2,979 , $ 6,357 and $ 2,705 related to restricted shares was recognized during the years ended December 31, 2019, 2018, and 2017, respectively. +The following table summarizes restricted stock award and restricted stock units activity under the Stock Plan: +Units +Weighted-Average +Grant Date Fair +Value +Issued and unvested, January 1, 2019 +357 +12.14 +Granted +329 +11.58 +Vested +( 212 +) +10.30 +Forfeited +( 10 +) +13.69 +Issued and unvested, December 31, 2019 +464 +$ +12.86 +Issued and expected to vest, December 31, 2019 +464 +$ +12.86 +F-29 +As of December 31, 2019, there was $ 3,200 of unrecognized compensation expense related to unvested restricted stock awards and unvested restricted stock units that is expected to be recognized over a weighted average period of 1.9 years. +In connection with the vesting of restricted shares during the years ended December 31, 2019, 2018 and 2017, we purchased and immediately retired 76 , 171 and 130 shares with aggregate values of $ 949 , $ 3,291 and $ 1,240 , respectively, in satisfaction of minimum tax withholding and exercise obligations. +We grant performance-based restricted stock units (“PSUs”) to certain executives. Vesting of these PSUs is dependent upon achievement of performance-based metrics during a one-year or three-year period, from the date of grant. Assuming achievement of each performance-based metric, the executive must also generally remain in our service for three years from the grant date. Performance during the one-year period will be based on a one-year earnings per share or income before taxes target. If the one-year target is achieved, the PSUs will then vest three years from grant date. Performance during the three-year period will be based on achievement of a three-year compound annual growth rate for consolidated product revenues. If the three-year target is achieved, the corresponding PSUs will then vest three years from grant date. PSUs are converted into shares of our common stock once vested. Upon grant of the PSUs, we recognize compensation expense related to these awards based on assumptions as to what percentage of each target will be achieved. The Company evaluates these target assumptions on a quarterly basis and adjusts compensation expense related to these awards, as appropriate. +Compensation cost of $( 83 ), $ 6,717 and $ 2,223 related to the PSUs was recognized during the years ended December 31, 2019, 2018 and 2017, respectively. +The following table summarizes PSU activity under the Stock Plan: +Units +Weighted- +Average Grant +Date Fair +Value +Issued and unvested, January 1, 2019 +661 +9.26 +Granted (1) +201 +12.98 +Performance adjustment (2) +168 +12.98 +Vested +( 505 +) +5.47 +Issued and unvested, December 31, 2019 +525 +$ +12.52 +Issued and expected to vest, December 31, 2019 +525 +$ +12.52 +1. +Grant activity for all PSUs disclosed at target. +2. +Reflects the performance adjustment based on actual performance measured at the end of the performance period. +In connection with the vesting of performance stock units during the year ended December 31, 2019 and 2018, we purchased and immediately retired 213 and 20 shares with aggregate values of $ 2,763 and $ 301 , respectively. No performance stock units vested in 2017. +Share Repurchase Program +On August 5, 2008, our Board of Directors approved a share repurchase program pursuant to which we are permitted to acquire up to $ 25,000 of our outstanding common shares. No shares were purchased and retired in 2019, 2018 or 2017. +1 3 . +TRANSITION COSTS +In January 2018, we announced the retirement of our President and CEO and our CFO and Chief Operating Officer. Stephen S. Tang, Ph.D., who served as Chairman of the Board of Directors (the “Board”), was appointed as the Company’s new President and CEO, effective as of April 1, 2018. Dr. Tang replaced Douglas A. Michels, who retired as President and CEO, and as a member of the Board, on March 31, 2018. In addition, Roberto Cuca was appointed as the Company’s new CFO, effective June 8, 2018. Mr. Cuca replaced Ronald H. Spair, our former CFO and Chief Operating Officer, who retired on that same date. Charges associated with these transitions were $ 9,602 during 2018 and are included in general and administrative expenses in the consolidated statement of income. These charges primarily reflect non-cash charges associated with modifications to existing stock grants held by the retiring executives and expenses associated with the onboarding of the Company’s new President and CEO. +F-30 +1 4 . +BUSINESS SEGMENT INFORMATION: +Our business consists of two segments: our “OSUR” business consists of the development, manufacture, marketing and sale of oral fluid diagnostic products and specimen collection devices using our proprietary technologies, other diagnostic products including immunoassays and other in vitro diagnostic tests that are used on other specimen types. Our molecular collections systems or “DNAG” business consists of the development, manufacture, marketing and sale of specimen collection kits that are used to collect, stabilize, transport and store samples of genetic material for molecular testing. Our collection kits are also used for the collection of first-void urine for liquid biopsy in the prostate and bladder cancer markets; and in the sexually transmitted infection screening market. In addition, our DNAG business provides microbiome laboratory services that accelerate research and discovery for customers in the pharmaceutical, agricultural, and academic research markets. Financial results of CoreBiome, Novosanis and Diversigen are included in our DNAG segment. Our cryosurgical system business was included in our OSUR segment and the impact of the sale of that business in August 2019 is reflected in the results presented below. +We organized our operating segments according to the nature of the products included in those segments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (see Note 2). We evaluate performance of our operating segments based on revenue and operating income. We do not allocate interest income, interest expense, other income, other expenses or income taxes to our operating segments. Reportable segments have no inter-segment revenues and inter-segment expenses have been eliminated. +Operating income (loss) for the year ended December 31, 2018 and 2017 has been modified to conform to the classification of the intercompany service fee presentation for 2019. Beginning with the first quarter of 2019, we have included the fees for intercompany services in our segment operating income (loss) in order to more accurately reflect the results of each segment. +The following table summarizes operating segment information for the years ended December 31, 2019, 2018, and 2017, and asset information as of December 31, 2019 and 2018: +Years Ended December 31, +2019 +2018 +2017 +Net revenues: +OSUR +$ +78,225 +$ +85,635 +$ +91,965 +DNAG +76,380 +96,108 +75,099 +Total +$ +154,605 +$ +181,743 +$ +167,064 +Operating income (loss): +OSUR +$ +154 +$ +( 15,188 +) +$ +( 1,685 +) +DNAG +18,457 +43,617 +41,923 +Total +$ +18,611 +$ +28,429 +$ +40,238 +Depreciation and amortization: +OSUR +$ +3,039 +$ +3,755 +$ +3,170 +DNAG +4,300 +3,467 +3,232 +Total +$ +7,339 +$ +7,222 +$ +6,402 +Capital expenditures: +OSUR +$ +6,073 +$ +4,893 +$ +2,752 +DNAG +3,241 +1,451 +1,585 +Total +$ +9,314 +$ +6,344 +$ +4,337 +December 31, +2019 +2018 +Total assets: +OSUR +$ +163,943 +$ +190,178 +DNAG +185,352 +125,393 +Total +$ +349,295 +$ +315,571 +F-31 +The following table represents total long-lived assets by geographic area: +December 31, +2019 +2018 +United States +$ +23,846 +$ +18,776 +Canada +5,697 +5,192 +Other regions +796 +331 +$ +30,339 +$ +24,299 +1 5 . +COMMITMENTS AND CONTINGENCIES: +Purchase Commitments +As of December 31, 2019, we had outstanding non-cancelable purchase commitments related to inventory, supplies, capital expenditures, and other goods or services as follows: +2020 +10,279 +2021 +20 +2022 +20 +2023 +18 +2024 +- +$ +10,337 +Employment Agreements +Under terms of employment agreements with certain employees, which extend through 2023, we are required to pay each individual a base salary for continuing employment with us as follows: +2020 +3,110 +2021 +1,682 +2022 +460 +2023 +309 +$ +5,561 +Litigation +From time to time, we are involved in certain legal actions arising in the ordinary course of business. In management’s opinion, the outcomes of such actions, either individually or in the aggregate, are not expected to have a material adverse effect on our future financial position or results of operations. +1 6 . +RETIREMENT PLANS: +Substantially all of our U.S. employees are eligible to participate in the OraSure Technologies, Inc. 401(k) Plan (the “401(k) Plan”). The 401(k) Plan permits voluntary employee contributions to be excluded from an employee’s current taxable income under provisions of Internal Revenue Code Section 401(k) and the regulations thereunder. The 401(k) Plan also provides for us to match employee contributions up to $ 4 per year. We contributed $ 754 , $ 721 and $ 617 to the 401(k) Plan, net of forfeitures, in 2019, 2018, and 2017, respectively. +In addition to our 401(k) plan, we offer a nonqualified deferred compensation plan to permit eligible directors and highly compensated employees of the Company to defer receipt and taxation of their compensation each year. We also may make discretionary contributions to the accounts of the participating employees in any amount either in cash or stock. Participants in the plan may not purchase OraSure stock as an investment vehicle. As of December 31, 2019 and 2018, the value of the assets associated with this plan was $ 3,519 and $ 3,884 , respectively, and is included in current assets and other assets in our consolidated balance sheets. Our +F-32 +obligation related to the deferred compensation plan is included in accrued expenses and other liabilities in our consolidated balance sheets. As of December 31, 201 9 and 201 8 , our total obligation under this plan was $ 3,519 and $ 3,884 , respectively. +Substantially all regular full-time Canadian employees are eligible to participate in the DNA Genotek Registered Retirement Savings Plan (the “RRSP”). The RRSP permits voluntary employee contributions to be excluded from an employee’s current taxable income and receive tax preferred treatment with Revenue Canada. The RRSP also provides for DNAG to match employee contributions up to $ 2 per year. We contributed $ 184 , $ 163 and $ 145 to the RRSP in 2019, 2018, and 2017, respectively. +1 7 . +QUARTERLY DATA (Unaudited): +The following tables summarize the quarterly results of operations for each of the quarters in 2019 and 2018. These quarterly results are unaudited, but in the opinion of management, have been prepared on the same basis as our audited financial information and include all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the information set forth herein. +2019 Results +Three months ended +March 31, 2019 +June 30, +2019 +September 30, 2019 +December 31, 2019 +Net revenues +$ +30,122 +$ +38,826 +$ +35,989 +$ +49,668 +Costs and expenses +33,933 +33,541 +22,937 +(1 +) +45,583 +Operating income (loss) +( 3,811 +) +5,285 +13,052 +(1 +) +4,085 +Other income, net +524 +524 +1,195 +477 +Income (loss) before income taxes +( 3,287 +) +5,809 +14,247 +4,562 +Income tax expense +( 29 +) +1,411 +1,169 +2,124 +Net income (loss) +$ +( 3,258 +) +$ +4,398 +$ +13,078 +$ +2,438 +Earnings (loss) per share +Basic +$ +( 0.05 +) +$ +0.07 +$ +0.21 +$ +0.04 +Diluted +$ +( 0.05 +) +$ +0.07 +$ +0.21 +$ +0.04 +2018 Results +Three months ended +March 31, 2018 +June 30, +2018 +September 30, 2018 +December 31, 2018 +Net revenues +$ +41,987 +$ +43,625 +$ +45,885 +$ +50,246 +Costs and expenses +42,485 +38,067 +35,028 +37,734 +Operating income +( 498 +) +5,558 +10,857 +12,512 +Other income, net +412 +736 +510 +1,629 +Income before income taxes +( 86 +) +6,294 +11,367 +14,141 +Income tax expense +2,033 +2,173 +3,271 +3,843 +Net income +$ +( 2,119 +) +$ +4,121 +$ +8,096 +$ +10,298 +Earnings per share +Basic +$ +( 0.03 +) +$ +0.07 +$ +0.13 +$ +0.17 +Diluted +$ +( 0.03 +) +$ +0.07 +$ +0.13 +$ +0.16 +(1) Includes a $ 10,149 gain associated with the sale of the cryosurgical business, which was recorded as a reduction of operating expenses in the indicated period. +F-33 \ No newline at end of file diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/filing_metadata.csv b/raw/filings/0001116463/2019/0001564590-20-008195/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..d3573b515d55423f679f5f6fe65a2a4feda165d5 --- /dev/null +++ b/raw/filings/0001116463/2019/0001564590-20-008195/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001116463,OSUR,ORASURE TECHNOLOGIES INC,10-K,2020-03-02,2019-12-31,2020-03-02T22:02:27.000Z,0001564590-20-008195,osur-10k_20191231.htm,10-K,18171245,1,1,https://www.sec.gov/Archives/edgar/data/1116463/000156459020008195/osur-10k_20191231.htm,https://www.sec.gov/Archives/edgar/data/1116463/000156459020008195/,2019,2019,1 diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/item1.txt b/raw/filings/0001116463/2019/0001564590-20-008195/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c54ec073256b6fc804ca63155a00edc1996dae98 --- /dev/null +++ b/raw/filings/0001116463/2019/0001564590-20-008195/item1.txt @@ -0,0 +1,270 @@ +ITEM 1. +Business. +The overall goal of our Company is to empower the global community to improve health and wellness by providing access to accurate essential information. Our business is made up of two principal segments. The first is our “OSUR” business, which consists of the development, manufacture, marketing and sale of oral fluid diagnostic products and specimen collection devices using our proprietary technologies, as well as other diagnostic products including immunoassays and other in vitro diagnostic tests that are used on other specimen types. Our diagnostic products include tests for diseases including HIV and Hepatitis C that are performed on a rapid basis at the point of care and tests that are processed in a laboratory. These products are sold in the United States and internationally to various clinical laboratories, hospitals, clinics, community-based organizations and other public health organizations, distributors, government agencies, physicians’ offices, and commercial and industrial entities. Our HIV product is also sold in a consumer-friendly format in the over-the-counter (“OTC”) market in the U.S. and as a self-test to individuals in a number of other countries. +The second segment is our “DNAG” or molecular products and services business and is operated primarily through our subsidiaries, DNA Genotek Inc. (“DNAG”), a company based in Ottawa, Canada, CoreBiome, Inc. (“CoreBiome”), Diversigen, Inc. (“Diversigen”) and Novosanis NV (“Novosanis”). In the DNAG business, we manufacture and sell kits that are used to collect, stabilize, transport and store biological samples of genetic material for molecular testing. Our products are used for academic research and commercial applications, including ancestry, disease risk management, lifestyle and animal testing. Included in the disease risk management area are pharmacogenomics testing, hereditary disease screening, prenatal or cancer screening, population health initiatives and other molecular testing using DNA or RNA for diagnosis of acute disease. Our Oragene ® DNA sample collection kit provides an all-in-one system for the collection, stabilization, transportation and storage of DNA from human saliva. We also sell research use only collection products into the microbiome market. We offer our customers a suite of genomics and microbiome services that range from package customization and study design optimization to extraction, analysis and reporting services. The microbiome laboratory and bioinformatics services are provided by CoreBiome and Diversigen. Novosanis manufactures and sells the Colli-Pee ® collection device for the volumetric collection of first-void urine for use in research, screening and diagnostics in the liquid biopsy and sexually transmitted infection markets. Our DNAG business serves customers in many countries worldwide, including many leading research universities and hospitals. +OraSure was formed in May 2000 under Delaware law solely for the purposes of combining two companies, STC Technologies, Inc. (“STC Technologies”) and Epitope, Inc. (“Epitope”), and changing the state of incorporation of Epitope from Oregon to Delaware. STC Technologies and Epitope were merged into OraSure on September 29, 2000. Our principal offices are located at 220 East First Street, Bethlehem, Pennsylvania 18015, and our telephone number is (610) 882-1820. +Additional information about us can be found on our website, www.orasure.com . We make available free of charge through a link provided at such website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and our other filings with the Securities and Exchange Commission (“SEC”), as well as any amendments to those Reports and filings. These Reports and filings are made available as soon as reasonably practicable after they are filed with or furnished to the SEC. Our website and the information contained in or connected to that website are not intended to be incorporated by reference into this Annual Report. +2019 Developments +In early January 2019, we acquired two privately-held, early-stage companies, CoreBiome and Novosanis, in order to add differentiated products and services to the molecular collection systems segment of our business. +CoreBiome, a spin-off from the University of Minnesota, is based in St. Paul, Minnesota and provides microbiome laboratory and analytical services that can accelerate research and discovery for customers in the pharmaceutical, agricultural and academic research communities. CoreBiome was co-founded in 2016 by Dr. Dan Knights, a globally-recognized expert in microbiome informatics who has developed leading methods for analyzing microbiome data, along with Dr. Daryl Gohl and Dr. Kenny Beckman, domain experts in microbiome sample processing and analysis. +Novosanis is a Belgian company that was founded in 2013 as a spin-off from the University of Antwerp, Belgium. Novosanis is an early commercial stage producer and distributor of urine sample collection devices targeting the liquid biopsy and sexually transmitted infection screening markets. Novosanis’ primary product is Colli-Pee, an easy to use device designed for the standardized collection of first-void urine which can be used in the privacy of the user’s home or in a clinic. Product validation and clinical trials are also under way with various sexually transmitted infection test manufacturers. +2 +I n August 2019, we sold our cryosurgical systems line of business to a third party . This line of business consisted of medical devices used for the removal of benign skin lesions by cryosurgery or freezing. +In November 2019, we acquired another microbiome laboratory services provider, Diversigen. Based in Houston, Texas, Diversigen provides science-driven, customized solutions for metagenomics sequencing, bioinformatics, and statistical analysis for the study of the microbiome. The company was founded in 2013 by Dr. Joseph Petrosino, director of the Alkek Center for Metagenomics and Microbiome Research at the Baylor College of Medicine (“BCM”), where Diversigen was a BCM portfolio company. Diversigen was the first company to establish microbiome protocols in accordance with College of American Pathologists (“CAP”) accreditation and Clinical Laboratory Improvements Amendments of 1988 (“CLIA”) guidelines. +OSUR Segment Products +The following is a summary of our principal products for the infectious disease and risk management markets, which comprise the OSUR segment of our business: +OraQuick ® Rapid HIV Test +OraQuick ® is our rapid point-of-care test platform designed to test oral fluid, whole blood (i.e., both finger-stick and venous), plasma and serum samples for the presence of various antibodies or analytes. The device uses a porous flat pad to collect an oral fluid specimen. After collection, the pad is inserted into a vial containing a pre-measured amount of developer solution and allowed to develop. When blood, plasma or serum is to be tested, a loop collection device is used to collect a drop of the specimen and mix it in the developer solution, after which the collection pad is inserted into the solution and allowed to develop. In all cases, the specimen and developer solution then flow through the testing device where test results are observable in approximately 20 minutes. The OraQuick ® device is a screening test and generally requires a confirmation test where an initial positive result is obtained. +This product is sold under the OraQuick ADVANCE ® name in North America, Europe and certain other countries and under the OraQuick ® name in other developing countries. The test has received pre-market approval (“PMA”) from the FDA for the detection of antibodies to both HIV-1 and HIV-2 in oral fluid, finger-stick whole blood, venous whole blood and plasma. This test is available for use by laboratories located in the United States certified under the Clinical Laboratory Improvements Amendment of 1988 (“CLIA”), to perform moderately complex tests. We have also received a CLIA waiver for use of the test with oral fluid and finger-stick and venous whole blood. As a result, the test can be used by numerous additional sites in the United States not certified under CLIA to perform moderately complex tests, such as outreach clinics, community-based organizations and physicians’ offices. +On the international front, we have obtained a CE mark for our OraQuick ADVANCE ® test so that we can sell this product in Europe and other countries accepting the CE mark for commercialization and this product is registered for sale in other countries. We have distributors in place for several countries and are seeking to increase awareness and expand our distribution network for this product throughout the world. We have also received World Health Organization (“WHO”) pre-qualification for our export-only version of this product. +OraQuick ® In-Home HIV Test +The OraQuick ® In-Home HIV test is an OTC oral-fluid only version of our OraQuick ADVANCE ® HIV 1/2 Antibody Test. We received PMA approval to sell this test in the U.S. OTC market. We have also received a CE mark for the OraQuick ® In-Home HIV test, although this product is not currently sold in the European Union. The In-Home test is performed in the same manner as the OraQuick ADVANCE ® test, except that it has product labeling and instructions designed for consumers. In addition, we have established toll-free, 24/7, 365-day per year customer telephone support to provide additional information and referral services for consumers that use this product. +OraQuick ® HIV Self-Test +The OraQuick ® HIV Self-Test uses the same diagnostic technology as our U.S. approved OraQuick ADVANCE ® HIV test but is sold for use by individuals in certain foreign countries at a lower cost to meet the needs of those markets. For the past several years, we worked with Population Services International (“PSI”), a leading global health organization, along with UNITAID, the WHO and health officials from several African countries to deploy our Self-Test through the UNITAID-PSI HIV Self-Testing in Africa (“STAR”) project. The OraQuick ® Self-Test has labeling and instructions specifically tailored for each market in which it is sold. The purpose of the STAR project was to generate crucial information about how best to deliver HIV self-testing, how to generate demand for HIV testing in this manner and what the potential public health impact of self-testing will be. Our OraQuick ® Self-Test was chosen by PSI because of its quality, ease-of-use and oral fluid option. The STAR project has largely been completed. This product has received WHO pre-qualification and is eligible for procurement by purchasing entities entitled to access funding and other resources from the Global Fund, UNITAID and other agencies. During 2019, a majority of the sales of our OraQuick ® HIV Self-Test occurred in countries outside of the African countries covered by the STAR project. +3 +OraQuick ® HCV Rapid Antibody Test +Another test available on the OraQuick ® platform is the OraQuick ® HCV rapid antibody test. This product is a qualitative test that can detect antibodies to the hepatitis C virus (“HCV”), in a variety of sample types. The OraQuick ® HCV test operates in substantially the same manner as the OraQuick ADVANCE ® HIV test. +We have received FDA approval and CLIA waiver for use of the test in detecting HCV antibodies in venous whole blood and finger-stick whole blood specimens, making it the first and only rapid HCV test approved by the FDA for use in the United States. The OraQuick ® HCV test has received a CE mark for use with oral fluid, venous whole blood, finger-stick whole blood, plasma and serum and is sold in Europe. This CE-marked product is also registered and sold in other foreign countries and has received WHO pre-qualification. +OraQuick ® Ebola Rapid Antigen Test +In 2019, we received 510(k) clearance from the FDA for our new rapid Ebola test, making it the first and only rapid Ebola test cleared for sale in the U.S. This product utilizes the OraQuick ® technology platform for the detection of Ebola antigen. Under this 510(k) clearance, which came through the FDA’s Breakthrough Devices Program that allows for expedited clearance for treatment or diagnosis of life-threatening or increasingly debilitating diseases, our test can be used with finger-stick and whole blood samples from live patients and oral fluid samples from recently deceased individuals. The uses for this test are limited to individuals that meet certain criteria indicating they may be infected with the Ebola virus, so the test is not available for general screening of individuals that do not meet this criteria. This test had previously received emergency use authorization (“EUA”) from the FDA for emergency use by laboratories and facilities adequately equipped, trained and capable of testing for Ebola infection (including treatment centers and public health clinics). The WHO also previously issued an Emergency Use Assessment and Listing for this product. +OraSure QuickFlu ® Rapid Flu A&B Test +The OraSure QuickFlu ® Rapid Flu A&B test is an FDA 510(k) cleared rapid qualitative test for the detection of influenza (flu) Types A and B, including H1N1 viral infections. The test utilizes specimen collected with a nasal swab, nasopharyngeal swab or nasal aspirate/wash. A reagent is first inserted into a test cartridge, the specimen is added and the test is allowed to flow. Results are available in as little as 10 minutes. This product is manufactured for us under an agreement with a third party and is currently sold in certain U.S. markets. The manufacturer of this product has also obtained a CLIA waiver for use of the test with nasal and nasopharyngeal swabs. +OraSure ® Collection Device +Our OraSure ® oral fluid collection device is used in conjunction with screening and confirmatory tests for HIV-1 antibodies. The generic version of this product can be used for other analytes. This device consists of a small, treated cotton-fiber pad on a handle that is placed in a person’s mouth for two to five minutes. The device collects oral mucosal transudate (“OMT”), a serum-derived fluid that contains higher concentrations of certain antibodies and analytes than saliva. As a result, OMT testing is a highly accurate method for detecting HIV-1 infection and other analytes. +The OraSure ® collection device is FDA approved for use in the detection of HIV-1 antibodies. The generic version is a Class I medical device for the detection of cocaine and cotinine in oral fluid specimens for risk assessment testing. HIV-1 antibody detection using the OraSure ® collection device involves three steps: +• +Collection of an oral fluid specimen using the OraSure ® device; +• +Screening of the specimen for HIV-1 antibodies at a laboratory with an enzyme immunoassay (“EIA”) screening test approved by the FDA for use with the OraSure ® device; and +• +Laboratory confirmation of any positive screening test results with either a western blot confirmatory test or a blood based nucleic acid test. +A trained health care professional then conveys test results and provides appropriate counseling to the individual who was tested. +Tuberculosis (“TB”) Products +OMNIgene ® • SPUTUM is a non-toxic and highly stable reagent that liquefies and decontaminates sputum samples at the point-of-collection or in the lab while preserving the viability of TB bacteria for at least eight (8) days at ambient temperatures. +Although the OMNIgene ® • SPUTUM product is CE marked and was being evaluated by a number of TB laboratories, demand for this product has not met expectations. Accordingly, we decided to stop selling this product in the second half of 2019. +4 +Intercept ® Drug Testing System +A collection device that is substantially similar to the OraSure ® device is sold under the name Intercept ® , and is used to collect oral mucosal transudate or OMT for oral fluid drug testing. We have received FDA 510(k) clearance to use the Intercept ® collection device with laboratory-based EIAs to test for drugs-of-abuse commonly identified by the National Institute for Drug Abuse (“NIDA”) as the NIDA-5 (i.e., tetrahydrocannabinol (“THC” or marijuana), cocaine, opiates, amphetamines/methamphetamines and phencyclidine (“PCP”)), and for barbiturates, methadone and benzodiazepines. Each of these EIAs is also FDA 510(k) cleared for use with the Intercept ® device. Our Intercept ® device and oral fluid assays are sold in the U.S. primarily through laboratory distributors. +We believe that the Intercept ® device has several advantages over competing urine and other drugs-of-abuse testing products, including its lower total testing cost, its non-invasive nature, mobility and accuracy, the ease of maintaining a chain-of-custody, the treatment of test subjects with greater dignity, no requirement for specially-prepared collection facilities and difficulty of sample adulteration. The availability of an oral fluid test is intended to allow our customers to test for drug impairment and eliminate scheduling costs and inconvenience, thereby streamlining the testing process. +We have also developed a next-generation collection device, which we are marketing under the tradename “Intercept i2 ® he ”. This device offers several important advantages over our original Intercept ® device, including a sample adequacy indicator that provides a visual prompt when the appropriate volume of oral fluid has been collected, the ability to collect a larger sample required by current laboratory testing protocols and a more optimized chemistry that results in improved recovery of the targeted drug analytes. The Intercept i2 ® he device is currently being sold as a forensic use only device within the criminal justice and drug treatment markets along with a NIDA-5 panel of fully-automated high-throughput oral fluid drug assays that we distribute under an agreement with Thermo Fisher Scientific (“Thermo Fisher”). Under an amendment to the Thermo Fisher agreement, we have agreed to modify the configuration of our Intercept i2 ® he device and Thermo Fisher will further optimize its assays and related calibrators in order to meet recently issued oral fluid drug testing guidelines issued by the Substance Abuse and Mental Health Services Administration (“SAMHSA”). We also intend to obtain FDA 510(k) clearance of our device for use with a 12-assay panel of the Thermo Fisher assays. +Immunoassay Tests and Reagents +We develop and sell immunoassay tests in formats, known as MICRO-PLATE and AUTO-LYTE ® , to meet the specific needs of our customers. We also sell fully-automated high-throughput oral fluid drug assays developed under our agreement with Thermo Fisher. +In a MICRO-PLATE kit, the sample to be tested is placed into a small plastic receptacle, called a microwell, along with the reagents. The result of the test is determined by the color of the microwell upon completion of the reaction. Controlling the reaction involves the use of reagents by laboratory personnel. Test results are analyzed by any of a variety of commercially available laboratory instruments, which we may also provide to our laboratory customers. MICRO-PLATE tests can be performed on commonly used instruments and can detect drugs in urine, serum and sweat specimens. MICRO-PLATE tests are also used as part of the Intercept ® product line to detect drugs-of-abuse in oral fluid specimens. +AUTO-LYTE ® tests are sold in the form of bottles of liquid reagents. These reagents are run on commercially available laboratory-based automated analytical instruments, which are manufactured by a variety of third parties. AUTO-LYTE ® is typically used in high volume, automated, commercial reference insurance laboratories to detect certain drugs or chemicals in urine. Test results are produced quickly, allowing for high throughput. Our AUTO-LYTE ® tests continue to face strong competition from cheaper “home-brew” tests developed internally by our laboratory customers. As a result, we may eventually stop selling our AUTO-LYTE ® tests. +We previously entered into an agreement with Thermo Fisher under which Thermo Fisher would develop and supply up to 12 fully-automated high-throughput oral fluid drug assays for use with our Intercept i2 ® device. Under this agreement, we are currently selling a NIDA-5 panel of assays supplied by Thermo Fisher in the U.S. forensic market. As noted above, the parties amended this agreement and have agreed to modify our Intercept i2 ® collector and optimize the assays and related calibrators to meet recently issued SAMHSA drug testing guidelines and to pursue FDA 510(k) clearance of the Intercept i2 ® device for use with a 12-assay panel. We believe the offering of an Intercept i2 ® device with a full menu of fully-automated high-throughput oral fluid assays that meet the SAMHSA guidelines will better meet the needs of our laboratory drug testing customers and allow us to compete more effectively against fully automated urine drug assays that dominate the drug testing market. +Q.E.D. ® Saliva Alcohol Test +Our Q.E.D. ® saliva alcohol test is a point-of-care test device that is a cost-effective alternative to breath or blood alcohol testing. The test is a quantitative, saliva-based method for the detection of ethanol, has been cleared for sale by the FDA and has received a CLIA waiver. The U.S. Department of Transportation (“DOT”) has also approved the test. +5 +Each Q.E.D. ® test kit contains a collection stick that is used to collect a sample of saliva and a disposable detection device that displays results in a format similar to a thermometer. The Q.E.D. ® device is easy to operate and instrumentation is not required to read the result. The product has a testing range of 0 to 0.145% blood alcohol and produces results in approximately two minutes. +Molecular Products and Services Segment +Genomic Products +We sell a number of genomic products that provide all-in-one systems for the collection, stabilization, transportation, and storage of DNA and/or RNA from human and animal biologic samples. Our lead products are sold under the Oragene ® and ORAcollect ® brands and are used to collect DNA from human saliva. These products are currently sold to thousands of academic research and commercial customers in many countries worldwide. +Our genomic products are available in several different configurations and contain proprietary chemical solutions that are optimized for the specific application for which each product is designed. Product physical design is focused on ease-of-use and reliability for self or assisted collection of samples. For example, several of the Oragene ® products require users to simply hold the product close to their mouth and spit into the collection device. When the container is closed, the reagents stored in the lid of the container are mixed with the captured saliva and immediately protect the nucleic acids in the sample. This non-invasive collection method yields nucleic acid that remains stable at ambient temperature for extended periods. The stabilizing technology results in high quality and high quantity nucleic acids that are required for most genetic testing and analysis methods. +We believe these products provide significant advantages over competing DNA and RNA collection methods such as blood collection or buccal swabs, particularly in human genetic applications. Benefits include the reliable collection of high-quality and stable genetic samples, use of simple non-invasive collection methods, the ability to store and transport collected samples for extended periods at ambient temperatures and compatibility with fully-automated laboratory testing systems. +We also sell the Colli-Pee ® collection device for the volumetric collection of first void urine samples. This product is used in liquid biopsy applications for the prostate and bladder cancer markets and in the sexually transmitted infection screening market. +Microbiome Products . +We also market several microbiome collection products designed to collect, stabilize and transport the microbial profile from multiple sample types. Unlike genomic DNA, the microbiome of a sample can change over time, especially when exposed to temperature and environment fluctuations. In order to optimize and standardize sample results, a reliable method that captures and preserves (“snapshots”) the microbiome after collection until analysis is required. We believe our products provide such a reliable method. +Our OMNIgene ® • GUT product is an all-in-one system designed to enable an individual to easily self-collect high quality microbial DNA from feces or stool samples for gut microbiome profiling for use in clinical laboratory and research settings. Current methodologies for gut microbiome profiling have distinct shortcomings due to the introduction of bias, leading to a lack of reproducibility in the field. Our product ensures that the fecal sample is fully stabilized immediately upon collection and maintains an accurate and reliable bacterial profile for weeks at room temperature. We have also begun marketing other microbiome collection kits for vaginal and oral samples. +Molecular Services . +Our molecular business also offers customers our GenoFIND TM services, a suite of genomic services that range from package customization and study design optimization to extraction, analysis and reporting services. Our GenoFIND TM offering has become an increasingly valuable tool for meeting the needs of our molecular customers. +Through our subsidiaries, CoreBiome and Diversigen, we also offer our customers microbiome laboratory testing and analytical services. CoreBiome provides its services with a focus on accelerating microbiome discovery for customers in the pharmaceutical, agriculture, and research communities, to unleash the translational potential of the microbiome. Through its proprietary BenchMark TM , BoosterShot TM , and Core Analysis TM platforms, CoreBiome provides fast and information-rich characterizations of microbial diversity and function paired with expert analytics. +Diversigen’s offering provides comprehensive microbiome and metagenomics services focused on solutions to improve human, animal and environmental health. Diversigen has extensive experience with highly diverse microbiome sample types and provides full project life cycle consulting services, including pre-project consulting, study design, extraction and sequencing to complete +6 +bioinformatics analysis. Diversigen is at the forefront for setting quality standards for this industry and was the first company to establish microbiome protocols that comply with CAP accreditation and CLI A guidelines. We are in the process of integrating the services offered through GenoFIND TM , CoreBiome and Diversigen into a unified offering and brand for our customers. +Regulatory Approvals. +Our molecular collection products historically have been sold primarily as Class I medical devices for use by research and academic institutions. We have received FDA 510(k) clearance of the Oragene ® • DX product for use with the eSensor ® Warfarin sensitivity saliva test. A separate 510(k) clearance permits self-collection by consumers when the sample is to be tested with either an exempt or 510(k) cleared molecular test. More recently, we received a generic 510(k) clearance for this product, which we believe will further broaden the use of our Oragene ® • DX device. Our ORAcollect ® product similarly received 510(k) clearance from the FDA. We have also received CE mark approval for the Oragene ® • DNA, ORAcollect ® and OMNIgene ® • GUT collection kits. Both CoreBiome and Diversigen provide molecular services in CLIA-certified laboratories and as noted above, Diversigen’s laboratory protocols comply with CAP guidelines. +Products Under Development +Infectious Disease +Our research and development efforts include programs targeted at expanding and enhancing our infectious disease business. These programs primarily focus on products related to drug monitoring, rapid tests for diseases other than HIV and HCV and drug testing. A significant amount of effort in 2020 will be devoted to modifying our Intercept ® i2he collection device and optimizing the Thermo Fisher fully-automated oral fluid drug assays to meet the recently issued SAMSHA drug testing guidelines. Another development area is focused on increasing the number of country registrations for our HIV Self-Test and expanding our self-testing franchise to include other diseases such as HCV. Finally, we are looking at both internal and external opportunities to develop rapid point-of-care assays for drug adherence testing in the same markets where we currently sell our infectious disease diagnostic products. +Molecular Product and Services +In order to intersect evolving customer needs within the academic and commercial markets, our molecular business product development pipeline is focused on extending offerings across different sample types and analytes within both the genomics and microbiome areas. Genomic customers are demonstrating an increasing demand for RNA collection and stabilization. On the microbiome front, we continue to focus research and development work on collecting and stabilizing microbial DNA, RNA and metabolites from multiple sample types including gut, skin, vagina and saliva. We are also evolving the physical design and features of our products to further enable high throughput processing through improved interoperability with automated platforms. +The field of microbiome services is fast paced with evolving biological understanding and development of new methodologies. Our development efforts are focused on remaining at the forefront of technology, as well as providing new and relevant services to our customers. These development goals are being pursued while we also leverage new sequencing technologies and methodologies to enable scalability for our business. +Research and Development +Research and development expenses were $19.6 million in 2019, $16.3 million in 2018 and $13.4 million in 2017. These expenses include our costs associated with research and development, regulatory affairs, clinical trials and product support. +Sales and Marketing +We attempt to reach our major target markets through a combination of direct sales, strategic arrangements and independent distributors. Our marketing strategy is to create or raise awareness through a full array of marketing activities, which include trade shows, print advertising, special programs, distributor promotions, telemarketing and the use of digital and social media in order to stimulate sales in each target market. +7 +We market our products in the United States and internationally. Consolidated net revenues attributable to customers in the United States were $ 107.3 million, $ 136.8 million and $121.5 million in 2019, 2018 and 2017 , respectively. Consolidated net revenues attributable to international customers amounted to $ 47.3 million, $ 44.9 million and $45.6 million , or 31 %, 25 % and 27% of our total revenues, in 2019, 2018 and 2017 , respectively. For more information about our revenues and long-lived assets attributable to U.S. and international customers, please see Note s 2 and 14 to our consolidated financial statements included elsewhere in this Annual Report. +Infectious Disease Testing - Professional +We market the OraQuick ADVANCE ® HIV-1/2 antibody test directly to customers in the public health market for HIV testing. This market consists of a broad range of clinics and laboratories and includes states, counties, and other governmental agencies, family planning clinics, colleges and universities, correctional facilities and the military. There are also a number of organizations in the public health market, such as AIDS service organizations and various community-based organizations that are set up primarily for the purpose of encouraging and enabling HIV testing. In the past, we sold our OraQuick ADVANCE ® test directly to hospitals in the U.S. through our internal sales force. We are now changing this approach to sell to hospitals primarily through distributors. We also use distributors to sell our OraQuick ADVANCE ® test into the U.S. physician office market and to retail clinics operated by pharmacies. In addition, we distribute our OraQuick ® HIV test in certain foreign countries through distributors. +Our OraQuick ® HCV test is sold primarily to the same markets where our OraQuick ® ADVANCE HIV test is sold, including public health organizations, hospitals, physicians and retail clinics. We also sell this test in other countries through distributors. +We initially sold our OraQuick ® Ebola test under an EUA and our only customer to date has been the CDC, which has purchased the product for field testing in Africa. There were approximately $200,000 of Ebola sales in 2019. Our ability to expand sales of this test to other customers will likely depend on the timing and extent of future outbreaks of the disease and the availability of government or other funding. We recently obtained FDA 510(k) clearance for this product and plan to request pre-qualification with the WHO. +We market the OraSure ® oral fluid collection device for HIV-1 testing, on its own and as a kit in combination with laboratory testing services. To better serve our public health customers, we have contracted a commercial laboratory to provide prepackaged OraSure ® test kits, with prepaid laboratory testing and specimen shipping costs included. +We also have distribution rights to an FDA 510(k) cleared and CLIA waived rapid flu A&B test, which we market under our proprietary OraSure QuickFlu ® tradename. Under our agreement with the supplier of this product, we are permitted to sell this product into the U.S. hospital and public health markets. +Infectious Disease Testing - OTC and Self-Test +We sell our OraQuick ® In-Home test in the U.S. retail or consumer market. Retailers carrying the product include CVS, Walgreens, Rite Aid and Walmart. The product is also available for purchase on-line through certain retailers and our website, www.oraquick.com . The primary target population for our HIV-OTC test comprises young, sexually active adults, with greater purchase intent found in high-risk sub-groups, such as men who have sex with men, African Americans and Latino Americans. +To support individuals that purchase and use our test, we offer toll-free customer support on a 24/7, 365-day per year basis. This service provides consumers with access to trained representatives who can answer questions about HIV/AIDS and the use of our test, and refer consumers to appropriate resources for follow-up confirmatory testing, counseling and medical treatment. +In 2016, we began selling our OraQuick ® HIV Self-Test to PSI (Population Services International) for use in a self-testing pilot program called the HIV Self-Testing in Africa, or STAR, project. Under Phase I of the project, our test was sold in three African countries, Malawi, Zambia and Zimbabwe. We were also selected to participate in Phase II of the project under which additional HIV Self-Tests were deployed. Although our participation in the STAR project has largely been completed, we registered our HIV Self-Test and continue to sell this product in other countries in Africa and elsewhere. +8 +In June 2017, we entered into a C haritable S upport A greement with the Bill & Melinda Gates Foundation (“Gates Foundation”) that has enable d us to offer our OraQuick ® HIV Self-Test at an affordable price in 50 developing countries in Africa and Asia with funding from the Gates Foundation. The funding consist s of support payments tied to the volume of product we sell and reimbursement of certain related costs. The agreement has a four-year term and enable s non-governmental organizations in the eligible countries that receive funding from government or public sector agencies and donors to access our HIV Self - Test at reduced pricing. The funding from the Gates Foundation will be in an aggregate amount not to exceed $20.0 million over the four-year term or $6.0 million each year of the agreement. +In July 2017, our OraQuick ® HIV Self-Test was prequalified by the WHO. WHO prequalification aims to ensure that diagnostic tests for high burden diseases meet global standards of quality, safety, and efficacy in order to optimize use of health resources and improve health outcomes. WHO prequalification enables governmental organizations implementing HIV Self-Test pilots and programs to access international funding to purchase our test. +Substance Abuse Testing +Our substance abuse testing products are marketed to laboratories serving the workplace testing, forensic toxicology, criminal justice and drug rehabilitation markets in the U.S. and certain international markets. +We have entered into agreements for the distribution of our Intercept ® collection device and associated MICRO-PLATE assays for drugs-of-abuse testing in the workplace testing market in the United States and Canada through several laboratory distributors and internationally for workplace, criminal justice and forensic toxicology testing through other distributors. We also market the Intercept ® collection device on its own and as a kit in combination with laboratory testing services. To better serve our workplace customers, we have contracted with commercial laboratories to provide prepackaged Intercept ® test kits, with prepaid laboratory testing and specimen shipping costs included. +The criminal justice market in the United States for our substance abuse testing products consists of a wide variety of entities in the criminal justice system that require drug screening, such as pre-trial services, parole and probation offices, police forces, drug courts, prisons, drug treatment programs and community/family service programs. The forensic toxicology market consists of several hundred laboratories including federal, state and county crime laboratories, medical examiner laboratories and reference laboratories. +As discussed above, we also sell our next generation Intercept i2 ® collection device with a NIDA-5 panel of fully-automated high-throughput oral fluid assays developed with Thermo Fisher for the detection of PCP, THC, opiates, cocaine, methamphetamines and amphetamines. These products are currently sold into the criminal justice and drug treatment markets. Under an amendment to our Thermo Fisher agreement, we plan to obtain FDA 510(k) clearance of our Intercept i2 ® device for use with the NIDA-5 assay panel, along with an additional six fully-automated high-throughput assays in order to expand sales of this product line into the workplace testing market and other markets that require 510(k) cleared drug tests. These products are expected to meet recently issued oral fluid drug testing guidelines issued by SAMHSA, which will enable us to expand sales into markets where employee drug testing is federally regulated. We expect that the 510(k) cleared Intercept i2 ® device and related fully-automated high-throughput assays will eventually replace our original Intercept ® collector and MICRO-PLATE assays in the drug testing market. +We distribute our Q.E.D. ® saliva alcohol test primarily through various distributors in the United States and internationally. The markets for alcohol testing are relatively small and fragmented with a broad range of legal and procedural barriers to entry. Markets range from law enforcement testing to workplace testing of employees in safety sensitive occupations. Typical usage situations include pre-employment, random, post-accident, reasonable-cause and return-to-duty testing. +Insurance Risk Assessment +We currently market the OraSure ® oral fluid collection device for use in screening life insurance applicants in the United States and internationally to test for three of the most important underwriting risk factors: HIV-1, cocaine and cotinine (a metabolite of nicotine). Devices are sold to insurance testing laboratories, which in turn sell the devices to insurance companies, usually in combination with testing services. +We also promote use of the OraSure ® device directly to insurance companies for life insurance risk assessment. Insurance companies then make their own decision regarding which laboratory to use to supply their collection devices and testing services. +There exists a wide range of policy limits where our OraSure ® product is being used. In general, many (but not all) of our insurance company customers use the OraSure ® device in connection with life insurance policies having face amounts of up to $250,000, with some customers using the device for policies of up to $500,000 in amount. Some insurance companies have chosen to extend their +9 +testing to lower policy limits where they did not test at all before, while others have used OraSure ® to replace some of their blood and urine-based testing. In recent years, some insurance customers have adopted a “Simplified Issues” policy, where lab testing is no longer required and instead the applicant completes a questionnaire about personal behaviors. +We also sell our AUTO-LYTE ® assays and reagents in the insurance testing market directly to certain laboratories. +Molecular Products and Services +DNAG sells its products directly to its customers, primarily through its own internal sales force. In many international markets, distributors are used. +Most of DNAG’s revenues are derived from product sales to commercial customers and into the academic and research markets. Sales to commercial customers providing consumer genetics and clinical diagnostic services have been increasing and account for a majority of DNAG’s revenues. A significant portion of DNAG’s sales are derived from repeat customers, in both markets. DNAG also has customers in the livestock and companion animal markets. +DNAG has expanded its market focus by developing new collection devices for the emerging microbiome market, which is focused on the study of microbes and their effect on human health. DNAG’s primary product offering in the microbiome market, OMNIgene ® • GUT, is focused on the human gut microbiome (microbes living in human stool). DNAG is leveraging its existing sales force and global research connections to engage microbiome customers around the world to establish itself as the leader in ease-of-collection, stabilization and transport of this challenging sample type. +During 2019, we began selling the Colli-Pee ® device for the volumetric collection of first void urine, as a result of our acquisition of Novosanis. This product is in its early stages and initial sales are occurring primarily through distributors and collaborations for use in the liquid biopsy and sexually transmitted disease markets. +DNAG is also offering laboratory and analytical services for both genomics and microbiome customers in order to more fully meet the needs of its customers. These services are primarily provided to pharmaceutical and biotech companies and research institutions. During 2019, we substantially expanded our ability to offer microbiome laboratory and bioinformatics services with the acquisition of CoreBiome and Diversigen. We expect to integrate the laboratory operations of CoreBiome and Diversigen so that we can provide a single-integrated offering to our customers. +Significant Products and Customers +Several different products have contributed significantly to our financial performance, accounting for 10% or more of our total revenues during the past three years. The table below shows a breakdown of those product revenues (dollars in thousands). +For the years ended December 31, +2019 +2018 +2017 +Oragene ® +$ +46,701 +$ +69,798 +$ +67,232 +OraQuick ® HIV +43,092 +41,457 +35,148 +OraQuick ® HCV +12,972 +12,394 +25,409 +One of our customers accounted for approximately 15%, 24% and 25% of our net consolidated revenues in 2019, 2018 and 2017, respectively. +Supply and Manufacturing +Our OraQuick ADVANCE ® HIV test, OraQuick ® In-Home HIV test, OraQuick ® HCV test, OraQuick ® Ebola test, OraSure ® , Intercept ® and Intercept i2 ® collection devices, AUTOLYTE and MICRO-PLATE assays and QED ® saliva alcohol test are all manufactured in our Bethlehem, Pennsylvania facilities. We expect to continue to manufacture these products at this location for the foreseeable future. +We have contracted with a third party in Thailand for the assembly of the OraQuick ® HIV device and the OraQuick ® HIV Self-Test in order to supply certain international markets. This supply agreement had an initial term of one year, and automatically renews for additional annual periods unless either party provides a timely notice of termination prior to the end of an annual period. We believe that other firms would be able to assemble these OraQuick ® tests on terms no less favorable than those set forth in the agreement if the Thailand contractor would be unable or unwilling to continue assembling this product. +10 +We can purchase the HIV antigens, the nitrocellulose and certain other critical components , and the HCV and Ebola antigens used in our OraQuick ® product lines only from a limited number of sources. If for any reason these suppliers are unwilling or no longer able to supply our antigen or nitrocellulose needs, we believe that alternative supplies could be obtained at a competitive cost. However, a change in any of the antigens, the nitrocellulose or other critical components used in our products would require FDA approval and some additional development work. This in turn could require significant time to complete, increase our costs and disrupt our ability to manufacture and sell the affected products. +Our MICROPLATE and AUTO-LYTE assays require the production of highly specific and sensitive antibodies corresponding to the antigen of interest. Substantially all our antibody requirements are provided by contract suppliers. We believe that we have adequate reserves of antibody supplies and that we have access to sufficient raw materials for these products. +Our OraSure QuickFlu ® test is manufactured and supplied under a private label agreement with a third party. There is no other supply source for this product. +The fully-automated high-throughput oral fluid drug assays sold with our new Intercept i2 ® collection device are manufactured and supplied under a long-term agreement with Thermo Fisher. There is no other supply source for these products. +DNAG has two long-term contract manufacturing relationships to supply virtually all of its products, including the Oragene ® product line. Many of the raw materials and components used in these products are also purchased from third parties, including one critical component that is purchased from a sole source supplier. We believe there are other suppliers that can manufacture and supply the raw materials and components for the DNAG products. +Our Colli-Pee ® device is currently manufactured at our Belgian assembly facility with components supplied by third party vendors. +Our GenoFIND TM genomics laboratory services are provided to our customers by a third party laboratory. We believe there are other laboratories that can also provide these services. Our microbiome laboratory testing and analytical services are provided by our subsidiaries, CoreBiome and Diversigen. +Employees +As of December 31, 2019, we had 472 full-time employees. Of this total, there were 139 in sales, marketing and client services; 58 in research and development; 187 in operations, manufacturing, quality control, information systems, purchasing and shipping; 44 in quality assurance and regulatory affairs; and 44 in administration and finance. This compares to 398 employees as of December 31, 2018. Our employees are not currently represented by a collective bargaining agreement. +Competition +OSUR Segment +The diagnostic industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger than we are, and have greater financial, research, manufacturing and marketing resources than we do. +The primary competitive factors for our products include price, quality, performance, ease of use, customer service and reputation. Industry competition is based on these and the following additional factors: +• +Scientific and technological capability; +• +Proprietary know-how; +• +The ability to develop and market products and processes; +• +The ability to obtain FDA or other regulatory approvals; +• +The ability to manufacture products that meet applicable FDA or other applicable regulatory requirements; +• +Commercial execution and strength of distribution; +• +Access to adequate capital; +• +The ability to attract and retain qualified personnel; and +• +The availability of patent protection. +11 +A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. +The future market for diagnostic products is expected to be characterized by greater cost consciousness, the development of new technologies, tighter reimbursement policies and consolidation. The purchasers of diagnostic products are expected to place increased emphasis on lowering costs, reducing inventory levels, obtaining better performing products, automation, service and volume discounts. The increased complexity of the market is expected to force many competitors to enter into joint ventures or license certain products or technologies. +We expect competition to intensify as technological advances are made and become more widely known, and as new products reach the market. Furthermore, new testing methodologies could be developed in the future that render our products impractical, uneconomical or obsolete. There can be no assurance that our competitors will not succeed in developing or marketing technologies and products that are more effective than those we develop or that would render our technologies and products obsolete or otherwise commercially unattractive. In addition, there can be no assurance that our competitors will not succeed in obtaining regulatory approval for these products, or introduce or commercialize them, before we can do so. These developments could have a material adverse effect on our business, financial condition and results of operations. +Several companies market or have announced plans to market oral specimen collection devices and tests both within and outside the United States. We expect the number of devices competing with our OraQuick ® , OraSure ® , Intercept ® and Intercept i2 ® devices to increase as the benefits of oral fluid-based testing become more widely accepted. +Competition in the U.S. market for infectious disease testing in medical settings is intense and is expected to increase. Our principal competition for HIV testing in the professional market comes from existing and new point-of-care rapid blood tests, automated laboratory-based blood tests, or other oral fluid-based tests. Our competitors sell both a rapid oral fluid HIV test and a rapid HIV antigen/antibody test that are both FDA approved and CLIA waived. Our OraQuick ® rapid HCV test competes against laboratory-based blood tests in the U.S., as there currently are no other rapid HCV testing products approved by the FDA. +Our competitors in the domestic infectious disease testing market include medical diagnostic companies and specialized biotechnology firms, as well as pharmaceutical companies with biotechnology divisions. Competing tests are often sold at a lower price than we charge for our products. This competition can result in lost sales and degradation of the price (and therefore the applicable profit margins) we can charge for our HIV and HCV tests. +Outside the U.S., our rapid HIV and HCV tests compete against other rapid and laboratory-based tests. Significant sales of these products in Europe have not materialized principally because of differences in European healthcare systems compared to U.S. systems. Unlike in the U.S., adoption of rapid point-of-care diagnostics is not widespread in Europe because laboratory testing is entrenched and healthcare systems are structured around centralized testing models. In addition, many competing tests in international markets are sold at very low prices. We intend to continue to build awareness and develop strategies to expand sales of our OraQuick ® HIV and HCV tests in European and other international markets. +Our OraQuick ® In-Home HIV oral fluid test is the only rapid HIV test approved by the FDA for sale in the U.S. OTC market. We compete against one other non-rapid HIV blood test available in the OTC market, which requires consumers to self-collect a blood sample and then send it to a laboratory for testing. We expect that other non-rapid HIV blood tests will eventually compete with our product. The OraQuick ® HIV Self-Test that we sell in certain international markets is facing competition from other blood-based rapid HIV self-tests. +Competition for our OraQuick ® Ebola test includes government and commercially-developed laboratory and point-of-care molecular tests, along with a small number of rapid antigen tests sold under an FDA EUA. Our Ebola test is the only product with FDA 510(k) clearance for use on both whole blood samples from living patients and oral fluid samples from cadavers. +The OraSure QuickFlu ® test competes primarily against other rapid flu tests sold by various third parties in the U.S. hospital and public health markets. +In the substance abuse testing market, our Intercept ® drug testing system competes with laboratory-based drug testing products using sample matrices such as urine, hair, sweat and oral fluid. We expect competition for our products to intensify, particularly from other domestic and international companies that have developed, or may develop, competing oral fluid drug testing products. +There are at least two competitors that sell fully-automated high-throughput oral fluid drug testing products in unregulated settings in the United States. These competitors sell these assays for use with either their own oral fluid collector or a collector manufactured by another party. These offerings compete against our Intercept ® and Intercept i2 ® collection devices and related oral fluid assays. +12 +Our MICRO-PLATE oral fluid drug assays, which are sold for use with the original Intercept ® collector and our OraSure ® collection device, also continue to come under increasing competitive pressure from “home-brew” assays developed internally by our laboratory customers. Our oral fluid MICRO-PLATE assays also compete with urine-based homogeneous assays that are run on fully-automated, random access analyzers. These tests provide strong competitive pressure because they provide the benefits of automation, including lower costs and short turn-around times. +Our MICRO-PLATE drugs-of-abuse reagents sold in the forensic toxicology market are targeted to forensic testing laboratories where sensitivity, automation and “system solutions” are important. In the past, these laboratories have typically had to rely on radioimmunoassay test methods to provide an adequate level of sensitivity. Radioimmunoassays require radioactive materials, which have a short shelf-life and disposal problems. Our MICRO-PLATE tests meet the laboratories’ sensitivity needs, run on automated equipment, are not radioimmunoassays, and are offered to the laboratory as a complete system solution of reagents, instrumentation and software to meet the specific needs of each customer. We compete with both homogeneous and heterogeneous tests manufactured by many companies. +Sales of our AUTO-LYTE ® urine assays have declined substantially over a number of years, primarily due to competition from “home-brew” assays developed internally by our laboratory customers, which can be produced at a cost lower than the price typically paid for our products. Many of our customers no longer purchase our AUTO-LYTE ® assays, and we may eventually stop selling this product line. +Q.E.D. ® competes against other semi-quantitative saliva-based alcohol tests that have received U.S. Department of Transportation approval as well as breath alcohol tests. Although there are lower priced tests on the market that use oral fluid or breath as a test medium, these tests are qualitative tests that are believed to be substantially lower in quality and provide fewer benefits than our Q.E.D. ® test. +Molecular Products and Services +Our Oragene ® and ORAcollect ® collection systems compete against other types of collection devices used for molecular testing, such as blood collection devices and buccal swabs, which often are sold for prices lower than the prices charged for the Oragene ® and ORAcollect ® products. Although we believe the Oragene ® and ORAcollect ® devices offer a number of advantages over these other products, the availability of lower price competitive devices can result in lost sales and degradation in pricing and profit margin. Our Oragene ® and ORAcollect ® products are also facing increasing competition from similarly designed collection systems which are beginning to enter the market. +OMNIgene ® • GUT is being sold in the emerging microbiome market and competes with a variety of non-standard in-house solutions developed by various researchers, including simply freezing the sample after collection. The microbiome market is expected to require standardization in the methods used for collection and stabilization in order to derive more accurate and repeatable results. To date, DNAG is one of the few vendors to offer a solution that fully meets these requirements. +Our genomic and microbiome laboratory service offerings primarily compete against a number of commercial reference laboratories, specialty laboratories and hospital laboratories in the U.S. +Patents and Proprietary Information +We seek patents and other intellectual property rights to protect and preserve our proprietary technology and our right to capitalize on the results of our research and development activities. We also rely on trade secrets, know-how, continuing technological innovations and licensing opportunities to provide competitive advantages for our products in our markets and to accelerate new product introductions. We regularly search for third-party patents in fields related to our business to shape our own patent and product commercialization strategies as effectively as possible and to identify licensing opportunities. United States patents generally have a maximum term of 20 years from the date an application is filed. +We have four United States patents and numerous foreign patents for the OraSure ® and Intercept ® collection devices and technology relating to oral fluid collection, containers for oral fluids, methods to test oral fluid, formulations for the manufacture of synthetic oral fluid, and methods to control the volume of oral fluid collected and dispersed. The U.S. patents expire from November 2021 to December 2026. We have also applied for additional patents, in both the United States and certain foreign countries, on such products and technology. +We have one United States patent for our OraQuick ® platform expiring in 2028, as well as corresponding related international patents. We also have patent applications pending internationally. +13 +We hold, through our subsidiary, DNAG, twenty United States patents and numerous foreign patents issued for compositions, methods and apparatuses for the collection, stabilization, transportation and storage of nucleic acids (DNA and RNA) from oral fluid and other bodily fluids and tissues. These patents expire from February 2022 through March 2035 . +We hold through our subsidiary, Novosanis, two United States patents and numerous foreign patents covering a medical device for capturing a predetermined volume of first void urine and an intradermal injection device for accurate injection of small volumes of drugs in the skin. These patents expire from April 2034 through April 2035. +Our subsidiary, CoreBiome, has licensed one United States patent and several foreign patent applications from the University of Minnesota for analytical standards to detect and/or measure sampling, processing, and/or amplification errors in a biological samples containing polynucleotide molecules. This license also covers certain software and know-how related to laboratory and bioinformatics procedures and processes. +Our subsidiary, Diversigen, has licensed certain know-how and database assets from the Baylor College of Medicine related to laboratory processes for microbiome and metagenomics services. +We require our employees, consultants, outside collaborators and other advisors to execute confidentiality agreements upon the commencement of employment or consulting relationships with us. These agreements provide that all confidential information developed by or made known to the individual during the course of the individual’s relationship with us is to be kept confidential and not disclosed to third parties except in specific circumstances. In the case of employees and certain consultants, the agreements also provide that all inventions conceived by the individual during his or her tenure with us or the performance by the consultant of services for us will be our exclusive property. +We own rights to trademarks and service marks that we believe are necessary to conduct our business as currently operated. In the United States, we own a number of trademarks, including the OraSure ® , Intercept ® , Intercept i2 ® , OraQuick ® , OraQuick ADVANCE ® , OraSure QuickFlu ® , Q.E.D. ® , Oragene ® , ORAcollect ® , OMNIgene ® , Diversigen ® , Colli-Pee ® , VAX-ID ® , AUTO-LYTE ® , prepIT ® and Hemagene ® trademarks. We also own many of these marks and others in several foreign countries and we are pursuing registration of several other trademarks. +Although important, the issuance of a patent or existence of trademark or trade secret protection does not in itself ensure the success of our business. Competitors may be able to produce products competing with our patented products without infringing our patent rights. Issuance of a patent in one country generally does not prevent manufacture or sale of the patented product in other countries. The issuance of a patent is not conclusive as to validity or as to the enforceable scope of the patent. The validity or enforceability of a patent or trademark can be challenged by litigation after its issuance or registration. If the outcome of such litigation is adverse to the owner of the patent, the owner’s rights could be diminished or withdrawn. Trade secret protection does not prevent independent discovery and exploitation of the secret product or technique. +Government Regulation +General +Most of our products are regulated by the U.S. Food and Drug Administration (“FDA”), along with other federal, state and local agencies and comparable regulatory bodies in other countries. This regulated environment governs almost all aspects of development, production and marketing, including product design and testing, authorizations to market, labeling, advertising and promotion, manufacturing, distribution, post-market surveillance and reporting, and recordkeeping. We believe that our products and procedures are in material compliance with all applicable regulations, but the regulations regarding the manufacture and sale of our products may be unclear and are subject to change. We cannot predict the effect, if any, that these changes might have on our business, financial condition or results of operations. +Many of our FDA-regulated products require some form of review and action by the FDA before they can be marketed in the United States. After approval or clearance by the FDA, we must continue to comply with other FDA requirements applicable to marketed products and are subject to periodic inspections by the FDA and other regulatory bodies. Both before and after approval or clearance, failure to comply with the FDA’s requirements can lead to significant penalties or could disrupt our ability to manufacture and sell these products. In addition, the FDA could refuse permission to obtain certificates needed to export our products if the agency determines that we are not in compliance. +14 +Domestic Regulation +Most of our products are regulated in the United States as in vitro diagnostic and medical devices. +There are several mechanisms by which regulated devices can be placed on the market in the United States. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act. To obtain this clearance from the FDA, the manufacturer must submit to the FDA a premarket notification that it intends to begin marketing the product, and show that the product is substantially equivalent to another legally marketed predicate device (i.e., a device that has been cleared through the 510(k) process; a device that was legally marketed prior to May 28, 1976; a device that has been downclassified by the FDA; or a device that FDA has previously determined to be exempt from the 510(k) process). To be substantially equivalent, an applicant must show that when compared to a predicate, the new device has the same intended use and same technology, or if different technology, that the new device is as safe and effective as the predicate and does not raise different questions of safety and effectiveness. In all cases, data from some form of performance testing is required and in some cases, the submission must include data from human clinical studies. An applicant must submit a 510(k) application at least 90 days before commercial distribution of the affected product commences. Marketing may only commence when the FDA issues a clearance letter finding that the new device is substantially equivalent to the predicate device. The standards and data requirements necessary for the clearance of a new device may be unclear or may be subject to change. Although FDA clearance usually takes from four to twelve months, in some cases more than a year may be required before clearance is obtained, if at all. +If the device does not qualify for the 510(k) procedure, either because there is no existing predicate device, it is not substantially equivalent to a legally marketed predicate device or because it is classified by the FDA as a high risk device, the FDA must approve either a request for de novo classification or a premarket approval application, or PMA, before marketing can begin. A de novo classification is an alternate pathway to classify novel devices of low to moderate risk for which no substantially equivalent predicate device exists. Clearance of a de novo request generally takes 150 days from the time of submission of the de novo request, although it can take longer. PMAs are generally required for devices that are determined to be high risk and must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness for the intended use(s) of the device. A PMA is typically a complex submission, supported by valid scientific evidence, including the results of preclinical and clinical studies, usability data, detailed information about the manufacturing process for the device, and other data and information. Preparing a PMA is a resource-intensive and time-consuming process. Once a PMA has been submitted, the FDA is required to review the submission within 180 days. However, the FDA’s review may be, and often is, much longer, in many cases requiring one to three years or more, and may include requests for additional data, review by an independent panel of experts, and facility inspections before approval is granted, if at all. +If the FDA approves the PMA, it may place restrictions on the device. If the FDA’s evaluation of the PMA or the manufacturing facility is not favorable, the FDA may deny approval of the PMA application or issue a “not approvable” letter. The FDA may also require additional clinical trials, which can delay the PMA approval process by several years or prevent a PMA approval from being obtained. +If the FDA discovers that an applicant has submitted false or misleading information in any application or notification, the FDA may take action against the applicant and its employees or refuse to review submissions until certain requirements are met pursuant to its Application Integrity Policy (AIP). Delays in receipt of or failure to receive such clearances or approvals, the loss of previously received clearances or approvals, or the failure to comply with existing or future regulatory requirements could have a material adverse effect on our business, financial condition and results of operations. +If there are any modifications made to our marketed devices, a new premarket notification or PMA supplement may be required to be submitted to, and approved by, the FDA, before the modified device may be marketed. A new PMA or a PMA supplement is required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s intended use(s), manufacturing process, manufacturing facility, critical components, labeling and design. Likewise, a new 510(k) clearance is required for any modification that could significantly affect the safety or effectiveness of the device, e.g. a significant change or modification in design, material, chemical composition, energy source, or manufacturing process or a major change or modification in the intended use(s) of the device. +A clinical trial may be required in support of a 510(k) submission and generally is required for a de novo or PMA application. These trials generally require an Investigational Device Exemption, or IDE, application approved in advance by the FDA for a specified number of patients, unless the proposed study is deemed to be exempt from the IDE requirements. In addition, if a study meets the requirements for a non-significant risk study, it may be eligible for compliance with “abbreviated” IDE requirements, which include a subset of the requirements applicable to significant risk medical device studies. If a full IDE is required, an IDE application must be supported by appropriate data, such as laboratory testing results, protocols for the proposed investigation, and other information demonstrating that the device is appropriate for use with humans in a clinical study. Clinical trials may begin if the IDE application is +15 +approved by the FDA and the appropriate institutional review boards, or IRBs, at the clinical trial sites. Submission of an IDE application does not give assurance that the FDA will issue the IDE. If the IDE application is approved, there can be no assurance the FDA will determine that the data derived from the trial(s) support the ultimate approval or clearance of the device or warrant the continuation of clinical trials. An IDE supplement must be submitted to and approved by the FDA before a sponsor or investigator may make a change to the investigational plan in such a way that may affect its scientific soundness, study indication or the rights, safety or welfare of human subjects. The trial must also comply with the FDA’s regulations, including the requirement that informed consent be obtained from each subject, and with clinical trial reporting regulations that require submission of information on certain clinical trials to a database maintained by the National Institutes of Health. Even if a trial is completed, the results of clinical testing may not adequately demonstrate the safety and efficacy of the device or may otherwise not be sufficient to obtain FDA clearance to market the product in the United States. +Some of our products are used for research only or other nonclinical or non-diagnostic purposes. Our molecular collection products are sold to many academic and research institutions for research purposes and our drugs-of-abuse products are sold to laboratories and clinics for forensic or other non-medical uses. The FDA does not currently regulate products used for these purposes, although other state and federal regulatory requirements may apply. +Another option for marketing a product in the U.S. is through an EUA that is granted by the FDA as a result of the Secretary of Health and Human Services declaring an emergency justifying the authorization of emergency use of certain in vitro diagnostic devices to aid in addressing the emergency. Typically, analytical and clinical studies are completed as required by the FDA. Products are exempt from design controls and other quality requirements in order to expedite development of diagnostic tools to aid in the diagnosis of viral pathogens that have the potential to affect public health. +Most devices distributed in the United States must comply with the FDA’s Quality System Regulations (“QSRs”), including current good manufacturing practices. These regulations govern the entire lifecycle of a medical device, including design, manufacture, testing, release, packaging, distribution, documentation and purchasing as well as complaint handling, corrective and preventative actions, and internal auditing. In complying with the QSRs, manufacturers must continue to expend time, money and effort in the area of production, quality, and postmarket surveillance to ensure full compliance. +Companies are also subject to other post-market and general requirements, including product listing and establishment regulations, which help facilitate FDA inspections and other regulatory action, post-market surveillance requests, restrictions imposed on marketed products, promotional standards and requirements for recordkeeping and reporting of certain adverse reactions and malfunctions. Device reporting regulations require that manufacturers report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur. +The FDA regularly inspects companies to determine compliance with the QSRs and other post-market requirements. Failure to comply with statutory requirements and the FDA’s regulations can result in an FDA Form 483 (which is issued by the FDA at the conclusion of an inspection when an investigator has observed any conditions that may constitute violations), public warning letters, monetary penalties against a company or its officers and employees, suspension or withdrawal of regulatory approvals, operating restrictions, total or partial suspension of production, injunctions, product recalls, product detentions, refusal to provide export certificates, seizure of products and criminal prosecution. We believe that our facilities and procedures are in material compliance with the FDA’s OSR regulations and other postmarket requirements, but the regulations are subject to change or may be unclear, and we cannot be sure that FDA investigators will agree with our compliance with the FDA’s postmarket requirements. +The Clinical Laboratory Improvement Amendments of 1988, or CLIA, prohibit any facility that conducts laboratory testing on specimens derived from humans from providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings, unless there is in effect for such facility a certificate issued by the U.S. Department of Health and Human Services applicable to the category of examination or procedure performed. Tests may be waived from this regulatory oversight if they meet certain requirements established under CLIA. We consider the applicability of CLIA requirements in the design and development of our products. We have obtained a waiver of the CLIA requirements for our OraQuick ADVANCE ® rapid HIV-1/2 antibody test, our OraQuick ® HCV rapid antibody test and our Q.E.D. ® alcohol saliva test and may seek similar waivers for certain other products. In addition, the supplier of the OraSure Quick-Flu ® test has obtained a CLIA waiver for that product. A CLIA waiver allows certain customers to use the waived products that may not have been able to use them without complying with applicable quality control and other requirements. +The laboratory services provided by our subsidiaries, CoreBiome and Diversigen, operate under the Clinical Laboratory Improvement Amendments of 1988, or CLIA, and consist of microbiome and metagenomics sequencing, bioinformatics and analysis. CoreBiome has recently received a CLIA certificate of registration in Minnesota and Diversigen operates under the Baylor College of Medicine CLIA certificate of compliance and CAP accreditation. A CLIA certificate of compliance is issued once a state regulator or the Center +16 +for Medicare and Medicaid Services determines that the laboratory is compliant with the applicable CLIA requirements. CAP accredits laboratories performing testing on specimens from human beings or animals, using methodologies and clinical applications within the expertise of the laboratory accreditation program. +Certain of our products may also be affected by state regulations in the United States, which can restrict the use and sale of certain diagnostic products. We are presently working with legislators or regulators in certain of these states in an effort to modify or remove any restrictions affecting our ability to sell products. +Advertising and Promotion +Advertising and promotion of medical devices, in addition to being regulated by the FDA, are also regulated by the Federal Trade Commission (“FTC”) and by other federal and state regulatory and enforcement authorities, including the Department of Justice (“DOJ”), the Office of Inspector General of the Department of Health and Human Services, and various state attorneys general. Although physicians are permitted to exercise medical judgment to use medical devices for indications other than those cleared or approved by the FDA, we may not promote our products for such “off-label” uses and can only market our products for cleared or approved uses. Promotional activities for FDA-regulated products of other companies have also been the subject of enforcement actions brought under healthcare reimbursement laws and consumer protection statutes. In addition, under the federal Lanham Act and similar state laws, competitors and others can initiate litigation relating to advertising claims. If the FDA determines that our promotional materials or training constitute promotion of an uncleared or unapproved use, it could request that we modify our training or promotional materials or subject us to regulatory or enforcement actions, including the issuance of an untitled letter, a notice of violation, a warning letter, injunction, seizure, civil fine or criminal penalties. FTC enforcement actions often result in consent decrees that constrain future actions. DOJ prosecutions can result in significant criminal and civil penalties, including exclusion from the Medicare and Medicaid programs. If an enforcement action is brought by the FDA or FTC, our reputation could be damaged and sales of our products could be impaired. +Import and Export Requirements +Products for export from the United States are subject to foreign countries’ import requirements and the exporting requirements of the FDA, as applicable. In particular, international sales of medical devices manufactured in the United States that are not approved or cleared by the FDA for use in the United States, or are banned or deviate from lawful performance standards, are subject to FDA export requirements. +Foreign countries often require, among other things, an FDA certificate for products for export, also called a Certificate for Foreign Government (“CFG”). To obtain this certificate from the FDA, the device manufacturer must apply to the FDA. The FDA certifies that the product has been granted clearance or approval in the United States and that the manufacturing facilities were in compliance with QSR regulations at the time of the last FDA inspection. If the FDA determines that our facilities or procedures do not comply with the QSR regulations, it may refuse to provide such certificates until we resolve the issues to the FDA’s satisfaction. Failure to obtain a CFG could inhibit our ability to export our products to countries that require such certificates. +International +We are also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval (or pre-qualification or endorsement) from international public health agencies, such as the World Health Organization, in order to sell products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for U.S. governmental approvals. We generally pursue approval only in those countries that we believe have a significant market opportunity. +The International Organization for Standardization (“ISO”) is a worldwide federation of national standards bodies from some 130 countries, established in 1947. The mission of the ISO is to promote the development of standardization and related activities in the world with a view to facilitating the international exchange of goods and services. ISO certification indicates that our quality system complies with standards applicable to activities ranging from initial product design and development through production and distribution. +In the European Union (“EU”), products that fall under the scope of the Medical Devices Directive (“MDD”) and the In Vitro Diagnostic Directive (“IVDD”) are not subject to the prior approval of a regulatory authority, but, depending on the class of product, may require prior review by a notified body. Notified bodies are accredited and supervised by national regulatory authorities to conduct conformity assessment procedures of medical devices or other products. Such products must comply with certain essential requirements listed in those directives. ISO certification creates a rebuttable presumption that the product satisfies the applicable +17 +requirements. Compliance with these requirements allows us to complete the applicable conformity assessment procedure, involving a notified body where necessary, and to affix the CE mark to our products, without which they may not be placed on the market in the EU. +In addition, the EU has adopted the EU Medical device Regulation (the “EU MDR”) and the In Vitro Diagnostic Regulation (the “EU IVDR”), each of which impose stricter requirements for the marketing and sale of medical devices, including in the area of clinical evaluation requirements, quality systems and post-market surveillance. Manufacturers of currently approved medical devices will have until May 2020 to meet the requirements of the EU MDR and until May 2022 to meet the EU IVDR. Compliance with these regulations may be expensive and time-consuming. Failure to meet these requirements could adversely impact our business in the EU and other regions that tie their product registrations to the EU requirements. +We have completed the applicable conformity assessment procedures and obtained the right to use the CE mark for the OraQuick ADVANCE ® HIV-1/2 test, OraQuick In-Home HIV Test, the OraQuick ® HCV test and certain of the Oragene ® collection kits and OMNIgene ® products sold by DNAG and the Colli-Pee ® first-void urine collection devices manufactured and sold by Novosanis. +We must also comply with certain registration and licensing requirements as dictated by Health Canada, prior to commencing sales in Canada. We have completed this process for several of our current products and may do so with respect to other products in the future. In addition, Canadian law requires manufacturers of medical devices to have a quality management system that meets various ISO requirements in order to obtain a license to sell their devices in Canada. Health Canada also requires all companies that market Class II, Class III and Class IV products in Canada to be certified as part of the Medical Device Single Audit Program (MDSAP). We received this certification for our OSUR segment in June 2019. +We have obtained WHO pre-qualification for our OraQuick ® HIV Self-Test and OraQuick ® HCV test and we will likely seek WHO pre-qualification or endorsement for certain other products sold into international markets. +Anti-Kickback and Other Fraud and Abuse Laws +The Federal Anti-Kickback Statute prohibits the knowing and willful offer, payment, solicitation, or receipt of any form of remuneration in return for, or to induce: +• +The referral of an individual to a person for the furnishing or arranging for the furnishing of items or services reimbursable under Medicare, Medicaid or other governmental healthcare programs; or +• +The purchase, lease, or order of, or the arrangement or recommendation of the purchasing, leasing, or ordering of any item or service reimbursable under Medicare, Medicaid, or other governmental healthcare programs. +Our products are or may be purchased by customers that will seek or receive reimbursement under Medicare, Medicaid or other governmental healthcare programs. Noncompliance with the federal anti-kickback statute can result in exclusion from Medicare, Medicaid or other governmental healthcare programs, and/or restrictions on our ability to operate in certain jurisdictions, as well as civil and criminal penalties, any of which could have an adverse effect on our business and results of operations. +The Federal Civil Monetary Penalties Law prohibits the offering or transferring of remuneration to a Medicare or Medicaid beneficiary that the person knows or should know is likely to influence the beneficiary’s selection of a particular provider, practitioner or supplier of Medicare or Medicaid payable items or services. Noncompliance can result in civil monetary penalties for each wrongful act, assessment of three times the amount claimed for each item or service and exclusion from the Federal healthcare programs. +Many states have also adopted some form of anti-kickback laws. A determination of liability under such laws could result in fines and penalties, restrictions on our ability to operate in these jurisdictions and significant damage to our reputation. +We are also subject to other federal and state laws targeting fraud and abuse in the healthcare industry, including false claims laws, marketing conduct laws and laws constraining the sales, marketing and other promotional activities of manufacturers of medical devices by limiting the kinds of financial arrangements, including sales programs, such manufacturers can enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. Violations of these laws may be punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government healthcare programs such as Medicare and Medicaid. These laws and regulations are wide ranging and subject to changing interpretation and application. In recent years, there has been greater scrutiny of marketing practices in the medical device industry which has resulted in several government investigations by various government authorities and the introduction and/or passage of federal and state legislation regulating interactions between medical device manufacturers and healthcare professionals and providers and requiring the disclosure by medical +18 +device manufacturers of payments to certain healthcare professionals and providers. For example, under the Sunshine Act provisions of the Affordable Care Act, device manufacturers are subject to new federal reporting and disclosure requirements with regard to payments or other transfers of value made to physicians and teaching hospitals. Reports submitted under the Sunshine Act are placed in a public database. Device manufacturers are required to submit annual reports by March 31 which cover the prior calendar year. To be in compliance with such disclosure laws, we have implemented necessary systems to accurately track gifts and other payments. +We have implemented a written Policy on Interactions with Health Care Professionals, which is based on the Code of Conduct for Interactions with Health Care Professionals promulgated by the Advanced Medical Technology Association, or AdvaMed, a leading trade association representing medical device manufacturers. The Policy applies to all employees and is intended to comply with applicable state and federal laws, regulations and government guidance. The Policy addresses interactions related to sales and marketing practices, research and development, product training and education, grants and charitable contributions, support of third-party educational conferences, and consulting arrangements. While we believe that our practices are in compliance with the Anti-Kickback and other fraud and abuse laws, the standards for compliance with such statutes can be unclear and subject to change. +Foreign Corrupt Practices Act and Other Anti-Corruption Laws +The U.S. Foreign Corrupt Practices Act (“FCPA”) prohibits corporations and individuals from engaging in certain activities to obtain or retain business or to influence a person working in an official capacity. It is illegal to use any means of interstate commerce corruptly in the furtherance of any offer, payment, promise to pay or authorization of payment of anything of value to any foreign government official, government staff member, political party or political candidate in an attempt to obtain or retain business or to otherwise influence a person working in an official capacity. Our present and future business has and will continue to be subject to the FCPA and various other laws, rules and/or regulations applicable to us as a result of our international sales. Those laws include the U.K. Bribery Act (the “Bribery Act”), which proscribes giving and receiving bribes in the public and private sectors, bribing a foreign public official, and failing to have adequate procedures to prevent employees and other agents from giving bribes. U.S. companies that conduct business in the United Kingdom generally will be subject to the Bribery Act. Penalties under the Bribery Act include potentially unlimited fines for companies and criminal sanctions for corporate officers under certain circumstances. +Environmental Regulation +Because of the nature of our current and proposed research, development, and manufacturing processes, we are subject to stringent federal, state and local laws, rules, regulations and policies governing the use, generation, manufacture, storage, air emission, effluent discharge and handling and disposal of solid wastes, hazardous materials and hazardous wastes. Products that we sell in Europe are subject to regulation in European Union, or EU, markets under the Restriction of the Use of Hazardous Substances Directive, or RoHS. RoHS prohibits companies from selling products which contain certain hazardous materials, including lead, mercury, cadmium, chromium, polybrominated biphenyls and polybrominated diphenyl ethers, in EU member states. In addition, the EU’s Registration, Evaluation, Authorization, and Restriction of Chemicals Directive also restricts substances of very high concern in products. +Future environmental laws may require us to alter our manufacturing processes, thereby increasing our manufacturing costs. We believe that our products and manufacturing processes at our facilities comply in all material respects with applicable environmental laws and worker health and safety laws; however, the risk of environmental liabilities cannot be completely eliminated. +The foregoing discussion of our business should be read in conjunction with the consolidated financial statements and accompanying notes included in Item 15 of this Annual Report. +19 \ No newline at end of file diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/item13.txt b/raw/filings/0001116463/2019/0001564590-20-008195/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..c96a0ed33d20ebd888a868c0fdd44d190d521f6d --- /dev/null +++ b/raw/filings/0001116463/2019/0001564590-20-008195/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated by reference to the information under the captions “Transactions with Related Persons” and “Corporate Governance - Director Independence” in the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/item9a.txt b/raw/filings/0001116463/2019/0001564590-20-008195/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..15539757f150b6f1882bf4d1a78a424aabc11466 --- /dev/null +++ b/raw/filings/0001116463/2019/0001564590-20-008195/item9a.txt @@ -0,0 +1,30 @@ +ITEM 9A. +Controls and Procedures. +(a) Evaluation of Disclosure Controls and Procedures . +The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of December 31, 2019. Based on that evaluation, the Company’s management, including such officers, concluded that as of December 31, 2019 the Company’s disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. +(b) Management’s Report on Internal Control Over Financial Reporting. +The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of the Company’s management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework, our management concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles as of December 31, 2019. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +The Company acquired CoreBiome, Inc., Novosanis NV, and Diversigen, Inc. collectively, the “acquired companies,” during 2019, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, the acquired companies’ representing approximately 11.7% of total assets and 4.0% of total revenues of the Company as of and for the year ended December 31, 2019. Management plans to fully integrate the operations of these businesses into the assessment of the effectiveness of the Company’s internal control over financial reporting in 2020. +62 +The effectiveness of our internal control over financial reporting as of December 31, 201 9 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included below. +(c) Changes in Internal Control Over Financial Reporting . +There were no changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +(d) Report of Independent Registered Public Accounting Firm . +To the Stockholders and Board of Directors +OraSure Technologies, Inc.: +Opinion on Internal Control Over Financial Reporting +We have audited OraSure Technologies, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission . In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and related notes (collectively, the consolidated financial statements), and our report dated March 2, 2020 expressed an unqualified opinion on those consolidated financial statements. +The Company acquired CoreBiome, Inc., Novosanis NV and Diversigen, Inc. (collectively, the “Acquired Companies”) during 2019, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, the Acquired Companies’ internal control over financial reporting associated with 11.7% of total assets and 4.0% of total revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2019. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of the Acquired Companies. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding +63 +prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Philadelphia, Pennsylvania +March 2, 2020 \ No newline at end of file diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/rp_note.txt b/raw/filings/0001116463/2019/0001564590-20-008195/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001116463/2019/0001564590-20-008195/rpt_disclosure.txt b/raw/filings/0001116463/2019/0001564590-20-008195/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..0a4c5285a76b772869bb6271ebece4d05f3d1029 --- /dev/null +++ b/raw/filings/0001116463/2019/0001564590-20-008195/rpt_disclosure.txt @@ -0,0 +1,6 @@ +TRANSACTIONS WITH RELATED PERSONS +Since January 1, 2019, there have been no transactions with related persons that would require disclosure in this Proxy Statement. The Audit Committee is required to review and approve in advance all transactions with related persons involving the Company. The Audit Committee may approve a related party transaction if the transaction is on terms +21 +comparable to those that could be obtained in arms’ length dealings with an unrelated third party. The Audit Committee also reviews any public disclosures of a related party transaction contained in our SEC filings. These responsibilities are described in the Audit Committee’s charter, a copy of which is available on our website at www.orasure.com . +Information regarding employment, severance and retirement agreements between our executive officers and the Company is set forth in the Section entitled, “Employment Agreements and Potential Payments Upon Termination or Change of Control,” in this Proxy Statement. +22 \ No newline at end of file diff --git a/raw/filings/0001116463/2020/0001564590-21-009887/item1.txt b/raw/filings/0001116463/2020/0001564590-21-009887/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c4c9bf993e06a5887bd1d86aaea95a839deee349 --- /dev/null +++ b/raw/filings/0001116463/2020/0001564590-21-009887/item1.txt @@ -0,0 +1,260 @@ +ITEM 1. +Business. +The overall goal of our Company is to empower the global community to improve health and wellness by providing access to accurate essential information. Our business is made up of two principal segments. The first is our Diagnostics business, previously named “OSUR”, which consists primarily of the development, manufacture, marketing and sale of oral fluid diagnostic products and specimen collection devices using our proprietary technologies, as well as other diagnostic products including immunoassays and other in vitro diagnostic tests that are used on other specimen types. Our diagnostic products include tests for diseases including HIV and Hepatitis C that are performed on a rapid basis at the point of care and tests that are processed in a laboratory. These products are sold in the United States and internationally to various clinical laboratories, hospitals, clinics, community-based organizations and other public health organizations, distributors, government agencies, physicians’ offices, and commercial and industrial entities. Our HIV product is also sold in a consumer-friendly format in the over-the-counter (“OTC”) market in the U.S. and as a self-test to individuals in a number of other countries. Our Diagnostics business includes the operations of UrSure Inc., which we acquired and merged into OraSure in 2020. This part of the business develops and commercializes products that determine adherence to HIV medications including pre-exposure prophylaxis or PrEP, the daily medication to prevent HIV infection. These products include laboratory-based tests that can measure levels of the medication in a patient’s urine or blood, as well as point-of-care products currently in development. +The second segment is our Molecular Solutions business, previously named “DNAG,” which is operated primarily through our subsidiaries, DNA Genotek Inc. (“DNAG”), a company based in Ottawa, Canada, Diversigen, Inc. (“Diversigen”) and Novosanis NV (“Novosanis”). In the Molecular Solutions business, we manufacture and sell kits that are used to collect, stabilize, transport and store biological samples of genetic material for molecular testing. Our products are used for academic research and commercial applications, including ancestry, disease risk management, lifestyle and animal testing. Included in the disease risk management area are pharmacogenomics testing, hereditary disease screening, prenatal or cancer screening, population health initiatives and other molecular testing using DNA or RNA for diagnosis of acute disease. We also sell research use only collection products into the microbiome market. We also offer our customers a suite of genomics and microbiome services that range from package customization and study design optimization to extraction, analysis and reporting services. The microbiome laboratory and bioinformatics services are provided by Diversigen, which includes the operations of CoreBiome, Inc. (“CoreBiome”), a subsidiary we acquired in early 2019. CoreBiome and Diversigen were merged together in 2020. Novosanis manufactures and sells the Colli-Pee ® collection device for the volumetric collection of first-void urine for use in research, screening and diagnostics in the liquid biopsy and sexually transmitted infection markets. Our Molecular Solutions business serves customers in many countries worldwide, including many leading research universities and hospitals. +Additional information about us can be found on our website, www.orasure.com . We make available free of charge through a link provided at such website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and our other filings with the Securities and Exchange Commission (“SEC”), as well as any amendments to those Reports and filings. These Reports and filings are made available as soon as reasonably practicable after they are filed with or furnished to the SEC. Our website and the information contained in or connected to that website are not intended to be incorporated by reference into this Annual Report. +Diagnostics Segment Products +The following is a summary of our principal products for the infectious disease and risk management markets, which comprise the Diagnostics segment of our business: +OraQuick ® Rapid HIV Test +OraQuick ® is our rapid point-of-care test platform designed to test oral fluid, whole blood (i.e., both finger-stick and venous), plasma and serum samples for the presence of various antibodies or analytes. The device uses a porous flat pad to collect an oral fluid specimen. After collection, the pad is inserted into a vial containing a pre-measured amount of developer solution and allowed to develop. When blood, plasma or serum is to be tested, a loop collection device is used to collect a drop of the specimen and mix it in the developer solution, after which the collection pad is inserted into the solution and allowed to develop. In all cases, the specimen and developer solution then flow through the testing device where test results are observable in approximately 20 minutes. The OraQuick ® device is a screening test and requires a confirmation test where an initial positive result is obtained. +3 +This product is sold under the OraQuick ADVANCE ® name in North America, Europe and certain other countries and under the OraQuick ® name in other developing countries. The test has received pre-market approval (“ PMA ”) from the U.S. Food and Drug Administration (“ FDA ”) for the detection of antibodies to both HIV-1 and HIV-2 in oral fluid, finger-stick whole blood, venous whole blood and plasma. This test is available for use by laboratories located in the United States certified under the Clinical Laboratory Improvements Amendment of 1988 (“ CLIA ”) , to perform moderately complex tests. We have also received a CLIA waiver for use of the test with oral fluid and finger-stick and venous whole blood. As a result, the test can be used by numerous additional sites in the United States not certified under CLIA to perform moderately complex tests, such as outreach clinics, community-based organizations and physicians’ offices. +On the international front, we have obtained a CE mark for our OraQuick ADVANCE ® test so that we can sell this product in Europe and other countries accepting the CE mark for commercialization and this product is registered for sale in other countries. We have distributors in place for several countries and are seeking to increase awareness and expand our distribution network for this product throughout the world. We have also received World Health Organization (“WHO”) pre-qualification for our export-only version of this product. +OraQuick ® In-Home HIV Test +The OraQuick ® In-Home HIV test is an OTC oral-fluid only version of our OraQuick ADVANCE ® HIV 1/2 Antibody Test. We received PMA approval to sell this test in the U.S. OTC market. We have also received a CE mark for the OraQuick ® In-Home HIV test, although this product is not currently sold in the European Union. The In-Home test is performed in the same manner as the OraQuick ADVANCE ® test, except that it has product labeling and instructions designed for consumers. In addition, we have established toll-free, 24/7, 365-day per year customer telephone support to provide additional information and referral services for consumers that use this product. +OraQuick ® HIV Self-Test +The OraQuick ® HIV Self-Test is sold for use by individuals in certain foreign countries at a lower cost to meet the needs of those markets. This product has received WHO pre-qualification and is eligible for procurement by purchasing entities entitled to access funding and other resources from the Global Fund, UNITAID and other agencies. +OraQuick ® HCV Rapid Antibody Test +Another test available on the OraQuick ® platform is the OraQuick ® HCV rapid antibody test. This product is a qualitative test that can detect antibodies to the hepatitis C virus (“HCV”), in a variety of sample types. The OraQuick ® HCV test operates in substantially the same manner as the OraQuick ADVANCE ® HIV test. +We have received FDA approval and CLIA waiver for use of the test in detecting HCV antibodies in venous whole blood and finger-stick whole blood specimens, making it the first and only rapid HCV test approved by the FDA for use in the United States. The OraQuick ® HCV test has received a CE mark for use with oral fluid, venous whole blood, finger-stick whole blood, plasma and serum and is sold in Europe. This CE-marked product is also registered and sold in other foreign countries and has received WHO pre-qualification. +OraQuick ® Ebola Rapid Antigen Test +We have received 510(k) clearance from the FDA for our rapid Ebola test, making it the first and only rapid Ebola test cleared for sale in the U.S. This product utilizes the OraQuick ® technology platform for the detection of Ebola antigen and can be used with finger-stick and whole blood samples from live patients and oral fluid samples from recently deceased individuals. The uses for this test are limited to individuals that meet certain criteria indicating they may be infected with the Ebola virus, so the test is not available for general screening of individuals that do not meet this criteria. +4 +OraSure ® Collection Device +Our OraSure ® oral fluid collection device is used in conjunction with screening and confirmatory tests for HIV-1 antibodies. The generic version of this product can be used for other analytes. This device consists of a small, treated cotton-fiber pad on a handle that is placed in a person’s mouth for two to five minutes. The device collects oral mucosal transudate (“OMT”), a serum-derived fluid that contains higher concentrations of certain antibodies and analytes than saliva. As a result, OMT testing is a highly accurate method for detecting HIV-1 infection and other analytes. +The OraSure ® collection device is FDA approved for use in the detection of HIV-1 antibodies. The generic version is a Class I medical device for the detection of cocaine and cotinine in oral fluid specimens for risk assessment testing. HIV-1 antibody detection using the OraSure ® collection device involves three steps: +• +Collection of an oral fluid specimen using the OraSure ® device; +• +Screening of the specimen for HIV-1 antibodies at a laboratory with an enzyme immunoassay (“EIA”) screening test approved by the FDA for use with the OraSure ® device; and +• +Laboratory confirmation of any positive screening test results with a blood-based nucleic acid test. +A trained health care professional then conveys test results and provides appropriate counseling to the individual who was tested. +Intercept ® Drug Testing System +A collection device that is substantially similar to the OraSure ® collection device is sold under the name Intercept ® , and is used to collect oral mucosal transudate or OMT for oral fluid drug testing. We have received FDA 510(k) clearance to use the Intercept ® collection device with laboratory-based EIAs to test for drugs-of-abuse commonly identified by the National Institute for Drug Abuse (“NIDA”) as the NIDA-5 (i.e., tetrahydrocannabinol (“THC” or marijuana), cocaine, opiates, amphetamines/methamphetamines and phencyclidine (“PCP”)), and for barbiturates, methadone and benzodiazepines. Each of these EIAs is also FDA 510(k) cleared for use with the Intercept ® device. Our Intercept ® device and oral fluid assays are sold in the U.S. primarily through laboratory distributors. +We believe that the Intercept ® device has several advantages over competing urine and other drugs-of-abuse testing products, including its lower total testing cost, its non-invasive nature, mobility and accuracy, the ease of maintaining a chain-of-custody, the treatment of test subjects with greater dignity, no requirement for specially-prepared collection facilities and difficulty of sample adulteration. The availability of an oral fluid test is intended to allow our customers to test for drug impairment and eliminate scheduling costs and inconvenience, thereby streamlining the testing process. +We have also developed a next-generation collection device, which we are marketing under the tradename “Intercept i2 ® he ”. This device offers several important advantages over our original Intercept ® device, including a sample adequacy indicator that provides a visual prompt when the appropriate volume of oral fluid has been collected, the ability to collect a larger sample required by current laboratory testing protocols and a more optimized chemistry that results in improved recovery of the targeted drug analytes. The Intercept i2 ® he device is currently being sold as a forensic use only device within the criminal justice and drug treatment markets along with a NIDA-5 panel of fully-automated high-throughput oral fluid drug assays that we distribute under an agreement with Thermo Fisher Scientific (“Thermo Fisher”). Under the Thermo Fisher agreement, we intend to obtain FDA 510(k) clearance of our device for use with a 12-assay panel of the Thermo Fisher assays that will meet the oral fluid drug testing guidelines issued by the Substance Abuse and Mental Health Services Administration (“SAMHSA”). +Immunoassay Tests and Reagents +We develop and sell immunoassay tests in formats, known as MICRO-PLATE and AUTO-LYTE ® , to meet the specific needs of our customers. We also sell fully-automated high-throughput oral fluid drug assays developed under our agreement with Thermo Fisher. Our MICRO-PLATE tests can be performed on commonly used instruments and can detect drugs in urine, serum and sweat specimens. MICRO-PLATE tests are also used as part of the Intercept ® product line to detect drugs-of-abuse in oral fluid specimens and we are selling a NIDA-5 panel of microplate assays supplied by Thermo Fisher to the U.S. forensic market under the agreement described above. AUTO-LYTE ® tests are sold in the form of bottles of liquid reagents, are run on commercially available laboratory-based automated analytical instruments, and are typically used in high volume, automated, commercial reference insurance laboratories to detect certain drugs or chemicals in urine. +5 +Q.E.D. ® Saliva Alcohol Test +Our Q.E.D. ® saliva alcohol test is a point-of-care test device that is a cost-effective alternative to breath or blood alcohol testing. The test is a quantitative, saliva-based method for the detection of ethanol, has been cleared for sale by the FDA and has received a CLIA waiver. The U.S. Department of Transportation (“DOT”) has also approved the test. +Each Q.E.D. ® test kit contains a collection stick that is used to collect a sample of saliva and a disposable detection device that displays results in a format similar to a thermometer. The Q.E.D. ® device is easy to operate and instrumentation is not required to read the result. The product has a testing range of 0 to 0.145% blood alcohol and produces results in approximately two minutes. +Molecular Solutions Segment +Genomic Products +We sell a number of genomic products that provide all-in-one systems for the collection, stabilization, transportation, and storage of DNA and/or RNA from human and animal biologic samples. Our lead products are sold under the Oragene ® and ORAcollect ® brands and are used to collect genetic material from human saliva. These products are currently sold to thousands of academic research and commercial customers in many countries worldwide. +Our genomic products are available in several different configurations and contain proprietary chemical solutions that are optimized for the specific application for which each product is designed. Product physical design is focused on ease-of-use and reliability for self or assisted collection of samples. For example, several of the Oragene ® products require users to simply hold the product close to their mouth and spit into the collection device. When the container is closed, the reagents stored in the lid of the container are mixed with the captured saliva and immediately protect the nucleic acids in the sample. This non-invasive collection method yields nucleic acid that remains stable at ambient temperature for extended periods. The stabilizing technology results in high quality and high quantity nucleic acids that are required for most genetic testing and analysis methods. +We believe these products provide significant advantages over competing DNA and RNA collection methods such as blood collection or buccal swabs, particularly in human genetic applications. Benefits include the reliable collection of high-quality and stable genetic samples, use of simple non-invasive collection methods, the ability to store and transport collected samples for extended periods at ambient temperatures and compatibility with fully-automated laboratory testing systems. +We also sell the Colli-Pee ® collection device for the volumetric collection of first void urine samples. This product is used in liquid biopsy applications for the prostate and bladder cancer markets and in the sexually transmitted infection screening market. +COVID Products +During 2020, we actively engaged with several laboratories and researchers to demonstrate the effectiveness of our existing collection products for use with COVID-19 molecular testing. The stabilization solution in our molecular collection products can accommodate a very broad spectrum of microbiome activity spanning bacteria to viruses and we have collected data on the usability of our kits for this purpose. We believe that oral samples collected using devices from our product lines for liquid saliva or oral swab samples are a suitable alternative to more commonly used samples collected with a nasopharyngeal or oropharyngeal swab. Unlike nasopharyngeal and oropharyngeal swabs which cannot be self-administered easily, our products are optimized for self-collection. That means healthcare providers, retailers, and online vendors could ship our kits directly to an individual’s home, eliminating unnecessary trips to hospitals, doctors’ offices and testing facilities. Self-collection would also support the social distancing guidelines already in place in many communities, reduce the burden on testing sites and healthcare facilities, and provide wider access to testing. Moreover, the chemistry in our products stabilizes nucleic acids, including RNA, which is the nucleic acid used by most labs for COVID-19 testing. The usability and form factor of these products are conducive to use in at-home or clinic settings. +As a result, during 2020 we began selling our ORAcollect ® • RNA and OMNIgene ® • ORAL collection devices for use in connection with COVID-19 molecular testing. These products have become an increasingly important part of our business and accounted for 47% of 2020 revenue generated by our Molecular Solutions segment. +6 +Microbiome Products . +We also market several microbiome collection products designed to collect, stabilize and transport the microbial profile from multiple sample types. Unlike genomic DNA, the microbiome of a sample can change over time, especially when exposed to temperature and environment fluctuations. In order to optimize and standardize sample results, a reliable method that captures and preserves (“snapshots”) the microbiome after collection until analysis is required. We believe our products provide such a reliable method. +Our OMNIgene ® • GUT product is an all-in-one system designed to enable an individual to easily self-collect high quality microbial DNA from feces or stool samples for gut microbiome profiling for use in clinical laboratory and research settings. Current methodologies for gut microbiome profiling have distinct shortcomings due to the introduction of bias, leading to a lack of reproducibility in the field. Our product ensures that the fecal sample is fully stabilized immediately upon collection and maintains an accurate and reliable bacterial profile for weeks at room temperature. We have also begun marketing other microbiome collection kits for skin, vaginal and oral samples. +Laboratory and Data Analytical Services . +Our Molecular Solutions business also offers our customers microbiome laboratory testing and analytical services. These services reflect the collective services of our CoreBiome and Diversigen subsidiaries, which were combined under the Diversigen name during 2020. Our services focus on accelerating microbiome discovery for customers in the pharmaceutical, agriculture, and research communities, to unleash the translational potential of the microbiome and provide fast and information-rich characterizations of microbial diversity and function paired with expert analytics. We also provide comprehensive microbiome and metagenomics services focused on solutions to improve human, animal and environmental health. Diversigen has extensive experience with highly diverse microbiome sample types and provides full project life cycle consulting services, including pre-project consulting, study design, extraction and sequencing to complete bioinformatics analysis. Diversigen is at the forefront for setting quality standards for this industry and is in the process of obtaining College of American Pathologists (“CAP”) accreditation at its laboratory facilities. We are also in the process of integrating the services offered through GenoFIND TM , CoreBiome and Diversigen into a unified offering and brand for our customers. +Regulatory Approvals. +Our Molecular Solutions products historically have been sold primarily as Class I medical devices for use by research and academic institutions. We have received FDA 510(k) clearance of the Oragene ® • DX product for use with the eSensor ® Warfarin sensitivity saliva test. A separate 510(k) clearance permits self-collection by consumers when the sample is to be tested with either an exempt or 510(k) cleared molecular test. More recently, we received a generic 510(k) clearance for this product, which we believe will further broaden the use of our Oragene ® • DX device. Our ORAcollect ® product similarly received 510(k) clearance from the FDA. We have also received CE mark approval for the Oragene ® • DNA, ORAcollect ® and OMNIgene ® • GUT collection kits. Diversigen provides molecular services in CLIA-certified laboratories and as noted above, and is in the process of obtaining CAP accreditation. +With respect to COVID testing, our collection devices have been included in FDA Emergency Use Authorizations (“EUAs”) granted to a number of third parties for use with COVID-19 molecular test offerings. These EUAs permit the use of our devices in healthcare settings or in some cases in at-home or unsupervised settings for the collection of samples. Our DNA Genotek subsidiary also received FDA EUAs for the use of its OMNIgene ® •ORAL and ORAcollect ® •RNA collection devices in COVID-19 testing which allows for the unsupervised use of these devices at home or in healthcare settings when used as part of an approved or validated at-home test kit. With these FDA authorizations, the OMNIgene ® • ORAL and ORAcollect ® •RNA devices can be used for the self-collection, transport and laboratory testing of saliva specimens suspected of containing SARS-CoV-2 ribonucleic acid (RNA), without the presence of a healthcare professional, before sending the sample to a lab for analysis. These products are also CE marked for in vitro diagnostic use, including for COVID-19 testing, in the European Union. +Products Under Development +Diagnostic Products +Our research and development efforts include programs targeted at expanding and enhancing our diagnostics business. These programs typically focus on products related to drug monitoring, rapid tests for diseases other than HIV and HCV and drug testing. In 2020, significant time and resources were dedicated to the development of our COVID-19 Rapid Antigen Self-Test. Subject to regulatory approvals, the Company intends to introduce its antigen test to the market for three different uses: +7 +▪ +Professional Test for use at drive-through sites, physician offices, public health testing sites, and employer/university health centers. In this instance, a physician would prescribe the test and the patient would conduct a self-swab in the presence of a healthcare provider who would then interpret the result. +▪ +Prescription Self-Test for use by individual consumers (with prescription) at home or in any location, by employers/universities on- or off-site, or by physicians or public health via remote testing. In this instance, a physician would prescribe the test and the patient would conduct a self-swab at home, or in any location, where they would then interpret their own result. +▪ +OTC Self-Test for use by consumers who would purchase online or at retail without prescription, and conduct the test and receive the result themselves anytime, anywhere. +We have completed development of the COVID-19 Rapid Antigen Self-Test and have collected all clinical study data to submit both the Prescription Self-Test and the Professional Test versions of this product for EUA at the same time, which is expected to occur in the first quarter of 2021. Subject to receipt of EUA, this product would test for active COVID-19 infection using nasal samples self-collected from the lower nostril. After we submit the Professional Test and Prescription Self-Test for EUA, we intend to continue plans to pursue an OTC claim. +During the third quarter of 2020, limit of detection studies for the assay were completed with live coronavirus in a certified third party analytical laboratory, with results comparable to that of another EUA approved, instrument-free, rapid antigen test. The results from the limit of detection comparison provides further confidence that the proprietary chemistries incorporated on OraSure’s lateral flow test strip will deliver the analytical sensitivity needed. Although the timing of EUA approval is subject to FDA review, the Company will be prepared to launch the test, subject to authorization, without delay following such approval. Subject to receipt of EUA, this product would test for active COVID-19 infection using nasal samples collected from the lower nostril. Results would be available at the point of collection, with no special instrumentation needed to interpret result. +In addition to a rapid antigen self-test, we are developing a lab-based oral fluid microplate SARS-CoV-2 antibody enzyme-linked immunosorbent assay (“ELISA”). The OraSure SARS-CoV-2 Antibody ELISA is intended for qualitative detection of total antibodies (including IgM/IgA/IgG) to SARS-CoV-2 in human oral fluid specimens collected with the OraSure Oral Antibody Collection Device. To date, there are no oral fluid antibody tests for COVID-19 authorized for sale in the U.S. Oral sample collection is quick, painless, non-invasive and requires less human contact in comparison to a blood draw, minimizing the need for personal protective equipment and exposure to potentially infected patients. With this test, individuals would use a collection pad to self-collect an oral fluid sample under the observation of a healthcare professional. The sample would then be placed into the OraSure oral antibody collection device buffer for storage and transport, and then later dispensed onto the ELISA microplate for testing in a laboratory. The lab-based antibody test can aid in identifying individuals with an adaptive immune response to SARS-CoV-2, indicating recent or prior infection. Antibody tests are well suited for community surveillance and seroprevalence studies to identify people in a population or community that have antibodies against an infectious disease such as COVID-19. In addition, the OraSure SARS-COV-2 Antibody ELISA can detect antibodies developed from vaccination. +In October 2020, the Company submitted an EUA application to the FDA for its SARS-CoV-2 Antibody ELISA test and in December 2020, the FDA requested additional information as part of its review of our EUA submission. At the FDA’s request, we are performing additional analytical studies on sample collection and stability and, after data from these studies have been obtained, we intend to resubmit two separate EUAs – one for the ELISA and one for the collection device. +During 2020, a significant amount of time was also devoted to the oral fluid drug assay development efforts with Thermo Fisher. Another development area focused on increasing the number of country registrations for our HIV Self-Test. Finally, we are also working to develop a rapid point-of-care assay to determine HIV drug adherence to be sold in the same markets where we currently sell our HIV diagnostic products. +Molecular Solutions +In order to intersect evolving customer needs within the academic and commercial markets, our molecular business product development pipeline is focused on extending offerings across different sample types and analytes within both the genomics and microbiome areas. Genomic customers are demonstrating an increasing demand for RNA collection and stabilization. On the microbiome front, we continue to focus research and development work on collecting and stabilizing microbial DNA, RNA and metabolites from multiple sample types including gut, skin, vagina and saliva. We are also evolving the physical design and features of our products to further enable high throughput processing through improved interoperability with automated platforms. +The field of microbiome services is fast paced with evolving biological understanding and development of new methodologies. Our development efforts are focused on remaining at the forefront of technology, as well as providing new and relevant services to our customers. These development goals are being pursued while we also leverage new sequencing technologies and methodologies to enable scalability for our business. +8 +Sales and Marketing +We attempt to reach our major target markets through a combination of direct sales, strategic arrangements and independent distributors. Our marketing strategy is to create or raise awareness through a full array of marketing activities, which include trade shows, print advertising, special programs, distributor promotions, telemarketing and the use of digital and social media in order to stimulate sales in each target market. +We market our products in the United States and internationally. Consolidated net revenues attributable to customers in the United States were $130.8 million, $107.3 million and $136.8 million in 2020, 2019 and 2018, respectively. Consolidated net revenues attributable to international customers amounted to $40.9 million, $47.3 million and $44.9 million, or 24%, 31% and 25% of our total revenues, in 2020, 2019 and 2018 respectively. For more information about our revenues and long-lived assets attributable to U.S. and international customers, please see Notes 2 and 13 to our consolidated financial statements included elsewhere in this Annual Report. +Diagnostics - Professional +We market the OraQuick ADVANCE ® HIV-1/2 antibody test directly to customers in the public health market for HIV testing. This market consists of a broad range of clinics and laboratories and includes states, counties, and other governmental agencies, family planning clinics, colleges and universities, correctional facilities and the military. There are also a number of organizations in the public health market, such as AIDS service organizations and various community-based organizations, that are set up primarily for the purpose of encouraging and enabling HIV testing. We sell our OraQuick ADVANCE ® test directly to hospitals in the U.S. primarily through distributors. We also use distributors to sell our OraQuick ADVANCE ® test into the U.S. physician office market and to retail clinics operated by pharmacies. In addition, we distribute our OraQuick ® HIV test in certain foreign countries through distributors. +Our OraQuick ® HCV test is sold primarily to the same markets where our OraQuick ® ADVANCE HIV test is sold, including public health organizations, hospitals, physicians and retail clinics. We also sell this test in other countries through distributors. +Diagnostics - OTC and Self-Test +We sell our OraQuick ® In-Home test in the U.S. retail or consumer market. Retailers carrying the product include CVS, Walgreens, Rite Aid and Walmart. The product is also available for purchase on-line through certain retailers and from our website, www.oraquick.com . The primary target population for our HIV-OTC test comprises young, sexually active adults, with greater purchase intent found in high-risk sub-groups, such as men who have sex with men, African Americans and Latino Americans. +We also sell our OraQuick ® HIV Self-Test in certain international markets. Under a Charitable Support Agreement with the Bill & Melinda Gates Foundation (“Gates Foundation”) we are able to offer our OraQuick ® HIV Self-Test at an affordable price in 50 developing countries in Africa and Asia with funding from the Gates Foundation. The funding consists of support payments tied to the volume of product we sell and reimbursement of certain related costs. The agreement was entered into in 2017 and has a four-year term and enables non-governmental organizations in the eligible countries that receive funding from government or public sector agencies and donors to access our HIV Self-Test at reduced pricing. The agreement with the Gates Foundation provides for an aggregate funding amount not to exceed $20.0 million over the four-year term or $6.0 million each year of the agreement. The term of this agreement expires in 2021. +Our OraQuick ® HIV Self-Test is the only oral fluid HIV test prequalified by the WHO. WHO prequalification helps ensure that diagnostic tests for high burden diseases meet global standards of quality, safety, and efficacy in order to optimize use of health resources and improve health outcomes. WHO prequalification enables governmental organizations implementing HIV Self-Test pilots and programs to access international funding to purchase our test. +Substance Abuse Testing +Our substance abuse testing products are marketed to laboratories serving the workplace testing, forensic toxicology, criminal justice and drug rehabilitation markets in the U.S. and certain international markets. +We have entered into agreements for the distribution of our Intercept ® collection device and associated MICRO-PLATE assays for drugs-of-abuse testing in the workplace testing market in the United States and Canada through several laboratory distributors and internationally for workplace, criminal justice and forensic toxicology testing through other distributors. We also market the Intercept ® collection device on its own and as a kit in combination with laboratory testing services. To better serve our workplace customers, we have contracted with commercial laboratories to provide prepackaged Intercept ® test kits, with prepaid laboratory testing and specimen shipping costs included. +9 +The criminal justice market in the United States for our substance abuse testing products consists of a wide variety of entities in the criminal justice system that require drug screening, such as pre-trial services, parole and probation offices, police forces, drug courts, prisons, drug treatment programs and community/family service programs. The forensic toxicology market consists of several hundred laboratories including federal, state and county crime laboratories, medical examiner laboratories and reference laboratories. +As discussed above, we also sell our next generation Intercept i2 ® collection device with a NIDA-5 panel of fully-automated high-throughput oral fluid assays developed with Thermo Fisher for the detection of PCP, THC, opiates, cocaine, methamphetamines and amphetamines. These products are currently sold into the criminal justice and drug treatment markets. Under our Thermo Fisher agreement, we intend to obtain FDA 510(k) clearance of our Intercept i2 ® device for use with the NIDA-5 assay panel, along with an additional six fully-automated high-throughput assays in order to expand sales of this product line into the workplace testing market and other markets that require 510(k) cleared drug tests. These products are expected to meet recent oral fluid drug testing guidelines issued by SAMHSA, which will enable us to expand sales into markets where employee drug testing is federally regulated. +We distribute our Q.E.D. ® saliva alcohol test primarily through various distributors in the United States and internationally. The markets for alcohol testing are relatively small and fragmented with a broad range of legal and procedural barriers to entry. Markets range from law enforcement testing to workplace testing of employees in safety sensitive occupations. Typical usage situations include pre-employment, random, post-accident, reasonable-cause and return-to-duty testing. +Molecular Solutions +Our Molecular Solutions business sells its products directly to its customers, primarily through its own internal sales force and in many international markets, distributors are used. +Most of our Molecular Solutions revenues are derived from product sales to commercial customers and sales into the academic and research markets. Sales to commercial customers providing consumer genetics and clinical diagnostic services have been increasing and account for a majority these revenues. A significant portion of total sales are derived from repeat customers in both markets. Molecular Solutions also has customers in the livestock and companion animal markets. +We have expanded the market focus of our Molecular Solutions business by selling certain existing collection products for use in COVID-19 tests and by developing new collection devices for the emerging microbiome market, which is focused on the study of microbes and their effect on human health. Our primary product offering in the microbiome market, OMNIgene ® • GUT, is focused on the human gut microbiome (microbes living in human stool). We are leveraging our existing sales force and global research connections to engage microbiome customers around the world to establish itself as the leader in ease-of-collection, stabilization and transport of this challenging sample type. +Our Molecular Solutions segment includes the Colli-Pee ® device, a product developed and sold by our Novosanis subsidiary, for the volumetric collection of first void urine. This product is in its early stages and initial sales are occurring primarily through distributors and collaborations for use in the liquid biopsy and sexually transmitted disease markets. +This segment is offering laboratory and analytical services for both genomics and microbiome customers in order to more fully meet the needs of its customers. These services are primarily provided to pharmaceutical and biotech companies and research institutions. During 2019, we substantially expanded our ability to offer microbiome laboratory and bioinformatics services with the acquisition of CoreBiome and Diversigen. The laboratory operations of CoreBiome and Diversigen were combined during 2020 so that we can now provide a single-integrated offering to our customers under the Diversigen brand. +Significant Products and Customers +Several different product lines have contributed significantly to our financial performance, accounting for 10% or more of our total revenues during the past three years. The table below shows a breakdown of those product lines (dollars in thousands). +For the years ended December 31, +2020 +2019 +2018 +Genomics +$ +37,141 +$ +56,200 +$ +79,765 +OraQuick ® HIV +44,224 +43,092 +41,457 +COVID-19 +49,802 +— +— +One of our customers accounted for approximately 15% and 24% of our net consolidated revenues in 2019 and 2018, respectively. We had no customers in 2020 that accounted for more than 10% of our net consolidated revenues. +10 +Supply and Manufacturing +We manufacture all of our OraQuick ADVANCE ® HIV test, OraQuick ® In-Home HIV test, OraQuick ® HCV test, OraQuick ® Ebola test, OraSure ® , Intercept ® and Intercept i2 ® collection devices, AUTOLYTE and MICRO-PLATE assays and QED ® saliva alcohol test in our Bethlehem, Pennsylvania facilities. We expect to continue to manufacture these products at this location for the foreseeable future. +We have contracted with a third party in Thailand for the assembly of the OraQuick ® HIV device and the OraQuick ® HIV Self-Test in order to supply certain international markets. We believe that other firms would be able to assemble these OraQuick ® tests on terms no less favorable than those set forth in the agreement if the Thailand contractor would be unable or unwilling to continue assembling this product. +We can purchase the HIV antigens, the nitrocellulose and certain other critical components, and the HCV and Ebola antigens used in our OraQuick ® product lines only from a limited number of sources. If for any reason these suppliers are unwilling or no longer able to supply our antigen or nitrocellulose needs, we believe that alternative supplies could be obtained at a competitive cost. However, a change in any of the antigens, the nitrocellulose or other critical components used in our products would require FDA approval and some additional development work. This in turn could require significant time to complete, increase our costs and disrupt our ability to manufacture and sell the affected products. +We intend to manufacture our COVID-19 Rapid Antigen Self-Test and OraSure SARS-CoV-2 Antibody ELISA in our Bethlehem, Pennsylvania facilities. In addition, we plan to manufacture our COVID-19 Rapid Antigen Self-Test at a third party in Thailand in order to supply certain international markets. We made significant capital investments during 2020 and will continue to invest to add the manufacturing capacity needed to meet the expected demand for these products. Specifically, we plan to add capacity of 70 million tests per year (which includes tests for HIV, HCV and Ebola) to meet demand for the COVID-19 Rapid Antigen Self-Test in the U.S. by the third quarter of 2021, and capacity for an additional 50 million tests per year by the second quarter of 2022 to support sales of this product outside of the U.S. We expect to add capacity of 20 million tests per year (including existing products) to meet demand for our OraSure SARS-CoV-2 Antibody ELISA by the fourth quarter of 2021. +Our MICROPLATE and AUTO-LYTE assays require the production of highly specific and sensitive antibodies corresponding to the antigen of interest. Substantially all our antibody requirements are provided by contract suppliers. We believe that we have adequate reserves of antibody supplies and that we have access to sufficient raw materials for these products. +The fully-automated high-throughput oral fluid drug assays sold with our new Intercept i2 ® collection device are manufactured and supplied under a long-term agreement with Thermo Fisher. There is no other supply source for these products. +DNAG has three long-term contract manufacturing relationships to supply virtually all of its products, including the Oragene ® product line. Many of the raw materials and components used in these products are also purchased from third parties, including one critical component that is purchased from a sole source supplier. We believe there are other suppliers that can manufacture and supply the raw materials and components for the DNAG products. We are increasing capacity for our molecular collection kits to meet demand for COVID molecular testing to 80 million kits per year (including non-COVID kits) by the third quarter of 2021. +Our Colli-Pee ® device is currently manufactured at our Belgian assembly facility with components supplied by third party vendors. +Our GenoFIND TM genomics laboratory services are provided to our customers by a third party laboratory. We believe there are other laboratories that can also provide these services. Our microbiome laboratory testing and analytical services are provided by our subsidiary, Diversigen. +11 +Human Capital Resources +In order to achieve the goals and expectations of our Company, it is crucial that we continue to attract and retain top talent. To facilitate talent attraction and retention, we strive to make OraSure a safe and rewarding workplace with opportunities for our employees to grow and develop in their careers. +As of December 31, 2020, we had 570 full-time employees, which compares to 472 employees as of December 31, 2019. The increase in employees during 2020 was primarily the result of the need to add manufacturing capacity for our COVID-19 Rapid Antigen Self-Test and molecular collection devices used in COVID-19 molecular testing. Our employees are not currently represented by a U.S. collective bargaining agreement. +We believe our employees are among our most important resources and are critical to our continued success. We focus significant attention to attracting and retaining talented and experienced individuals to manage and support our operations, and our management team routinely reviews employee turnover rates at various levels of the organization. Management also reviews employee engagement and satisfaction surveys to monitor employee morale and receive feedback on a variety of issues. +The health and safety of our workforce is fundamental to the success of our business. We safeguard our people, projects and reputation by striving for zero employee injuries and illnesses, while operating and delivering our work responsibly and sustainably. We provide our employees upfront and ongoing safety training to ensure that safety policies and procedures are effectively communicated and implemented. Personal protective equipment is provided to those employees where needed for the employee to safely perform their job function. +During 2020, in response to the COVID-19 pandemic, we implemented safety protocols and new procedures to protect our employees, our subcontractors and our customers. These protocols include complying with social distancing and other health and safety standards as required by federal, state and local government agencies, taking into consideration guidelines of the Centers for Disease Control and Prevention and other public health authorities. In addition, we modified the way we conduct many aspects of our business to reduce the number of in-person interactions. For example, we significantly expanded the use of virtual interactions in all aspects of our business, including customer facing activities. Many of our administrative and operational functions during this time have required modification as well, including much of our workforce working remotely. +As part of our compensation philosophy, we believe that we must offer and maintain market competitive compensation and benefits programs for our employees in order to attract and retain superior talent. In addition to healthy base wages, additional programs include annual bonus opportunities, a Company matched 401(k) Plan or other savings plan, healthcare and insurance benefits, health savings and flexible spending accounts, paid time off, family leave, flexible work schedules, and employee assistance programs. +The OraSure family of companies is committed to creating and fostering a diverse, equitable, and inclusive workplace that reflects and contributes to the global communities in which we do business and the customers and partners we serve. This includes all communities impacted by our corporate presence. Our management teams and all of our employees are expected to exhibit and promote honest, ethical and respectful conduct in the workplace. All of our employees must adhere to a Code of Conduct that sets standards for appropriate behavior and includes required annual training on preventing, identifying, reporting and stopping any type of unlawful discrimination. We strive to recruit the best people for the job regardless of gender, ethnicity or other protected trait and it is our policy to fully comply with all laws (domestic and foreign) applicable to discrimination in the workplace. We have an active Diversity, Equity and Inclusion Council that strives to drive diversity, equity and inclusion within the workplace. At OraSure, we believe a variety of perspectives are critical to achieving success, and that diversity, equity and inclusion are key drivers to growth-based innovation and profitability. We aim to create a culture where all people feel valued, supported, and inspired to be themselves fearlessly, without judgement. We believe that when all voices are heard, we honor and exemplify our core values and best serve our communities. +Competition +Diagnostics Segment +The diagnostic industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger than we are, and have greater financial, research, manufacturing and marketing resources than we do. +The primary competitive factors for our products include price, quality, performance, ease of use, customer service and reputation. Industry competition is based on these and the following additional factors: +• +Scientific and technological capability; +• +Proprietary know-how; +• +The ability to develop and market products and processes; +12 +• +The ability to obtain FDA or other regulatory approvals; +• +The ability to manufacture products that meet applicable FDA or other applicable regulatory requirements; +• +Commercial execution and strength of distribution; +• +Access to adequate capital; +• +The ability to attract and retain qualified personnel; and +• +The availability of patent protection. +A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. +The future market for diagnostic products is expected to be characterized by greater cost consciousness, the development of new technologies, tighter reimbursement policies and consolidation. The purchasers of diagnostic products are expected to place increased emphasis on lowering costs, reducing inventory levels, obtaining better performing products, automation, service and volume discounts. The increased complexity of the market is expected to force many competitors to enter into joint ventures or license certain products or technologies. +We expect competition to intensify as technological advances are made and become more widely known, and as new products reach the market. Furthermore, new testing methodologies could be developed in the future that render our products impractical, uneconomical or obsolete. There can be no assurance that our competitors will not succeed in developing or marketing technologies and products that are more effective than those we develop or that would render our technologies and products obsolete or otherwise commercially unattractive. In addition, there can be no assurance that our competitors will not succeed in obtaining regulatory approval for these products, or introduce or commercialize them, before we can do so. These developments could have a material adverse effect on our business, financial condition and results of operations. +Several companies market or have announced plans to market oral specimen collection devices and tests both within and outside the United States. We expect the number of devices competing with our OraQuick ® , OraSure ® , Intercept ® and Intercept i2 ® devices to increase as the benefits of oral fluid-based testing become more widely accepted. +Competition in the U.S. market for infectious disease testing in medical settings is intense and is expected to increase. Our principal competition for HIV testing in the professional market comes from existing and new point-of-care rapid blood tests, automated laboratory-based blood tests, or other oral fluid-based tests. Our competitors sell both a rapid oral fluid HIV test and a rapid HIV antigen/antibody test that are both FDA approved and CLIA waived. Our OraQuick ® rapid HCV test competes against laboratory-based blood tests in the U.S., as there currently are no other rapid HCV testing products approved by the FDA. +Our competitors in the domestic infectious disease testing market include medical diagnostic companies and specialized biotechnology firms, as well as pharmaceutical companies with biotechnology divisions. Competing tests are often sold at a lower price than we charge for our products. This competition can result in lost sales and degradation of the price (and therefore the applicable profit margins) we can charge for our HIV and HCV tests. +Outside the U.S., our rapid HIV and HCV tests compete against other rapid and laboratory-based tests. Significant sales of these products in Europe have not materialized principally because of differences in European healthcare systems compared to U.S. systems. Unlike in the U.S., adoption of rapid point-of-care diagnostics is not widespread in Europe because laboratory testing is entrenched and healthcare systems are structured around centralized testing models. In addition, many competing tests in international markets are sold at very low prices. We intend to continue to build awareness and develop strategies to expand sales of our OraQuick ® HIV and HCV tests in European and other international markets. +Our OraQuick ® In-Home HIV oral fluid test is the only rapid HIV test approved by the FDA for sale in the U.S. OTC market. We compete against one other non-rapid HIV blood test available in the OTC market, which requires consumers to self-collect a blood sample and then send it to a laboratory for testing. We expect that other non-rapid HIV blood tests will eventually compete with our product. The OraQuick ® HIV Self-Test that we sell in certain international markets is facing competition from other blood-based rapid HIV self-tests. +In the United States there are currently four rapid COVID-19 self-tests on the market that are expected to compete against our COVID-19 Rapid Antigen Self-Test. There are several other Professional point of care COVID-19 antigen tests with EUA in the United States which are expected to compete with the Professional use version of our antigen test. In addition, there are a number of COVID-19 blood-based antibody tests sold in the U.S. market that are expected to compete against our OraSure SARS-CoV-2 Oral +13 +Fluid Antibody ELISA. We also expect additional rapid COVID-19 antigen tests and COVID-19 antibody tests to enter the market both in the U.S. and in international markets that will compete against our COVID-19 assays. +In the substance abuse testing market, our Intercept ® drug testing system competes with laboratory-based drug testing products using sample matrices such as urine, hair, sweat and oral fluid. We expect competition for our products to intensify, particularly from other domestic and international companies that have developed, or may develop, competing oral fluid drug testing products. +There are at least two competitors that sell fully-automated high-throughput oral fluid drug testing products in unregulated settings in the United States. These competitors sell these assays for use with either their own oral fluid collector or a collector manufactured by another party. These offerings compete against our Intercept ® and Intercept i2 ® collection devices and related oral fluid assays. +Our MICRO-PLATE oral fluid drug assays, which are sold for use with the original Intercept ® collector and our OraSure ® collection device, also continue to come under increasing competitive pressure from “home-brew” assays developed internally by our laboratory customers. Our oral fluid MICRO-PLATE assays also compete with urine-based homogeneous assays that are run on fully-automated, random access analyzers. These tests provide strong competitive pressure because they provide the benefits of automation, including lower costs and short turn-around times. +Our MICRO-PLATE drugs-of-abuse reagents sold in the forensic toxicology market are targeted to forensic testing laboratories where sensitivity, automation and “system solutions” are important. We compete with both homogeneous and heterogeneous tests manufactured by many companies. +Q.E.D. ® competes against other semi-quantitative saliva-based alcohol tests that have received U.S. Department of Transportation approval as well as breath alcohol tests. Although there are lower priced tests on the market that use oral fluid or breath as a test medium, these tests are qualitative tests that are believed to be substantially lower in quality and provide fewer benefits than our Q.E.D. ® test. +Molecular Solutions Segment +Our Oragene ® and ORAcollect ® collection systems compete against other types of collection devices used for molecular testing, such as blood collection devices and buccal swabs, which often are sold for prices lower than the prices charged for the Oragene ® and ORAcollect ® products. Although we believe the Oragene ® and ORAcollect ® devices offer a number of advantages over these other products, the availability of lower price competitive devices can result in lost sales and degradation in pricing and profit margin. Our Oragene ® and ORAcollect ® products are also facing increasing competition from similarly designed collection systems which are beginning to enter the market. With the receipt of authorizations for use in connection with COVID-19 molecular tests, our Oragene ® and ORAcollect ® products now compete against COVID-19 testing systems and the collection methods used in those systems. +OMNIgene ® • GUT is being sold in the emerging microbiome market and competes with a variety of non-standard in-house solutions developed by various researchers, including simply freezing the sample after collection. The microbiome market is expected to require standardization in the methods used for collection and stabilization in order to derive more accurate and repeatable results. To date, we are one of the few vendors to offer a solution that fully meets these requirements. +Our genomic and microbiome laboratory service offerings primarily compete against a number of commercial reference laboratories, specialty laboratories and hospital laboratories in the U.S. +Patents and Proprietary Information +We seek patents and other intellectual property rights to protect and preserve our proprietary technology and our right to capitalize on the results of our research and development activities. We also rely on trade secrets, know-how, continuing technological innovations and licensing opportunities to provide competitive advantages for our products in our markets and to accelerate new product introductions. We regularly search for third-party patents in fields related to our business to shape our own patent and product commercialization strategies as effectively as possible and to identify licensing opportunities. United States patents generally have a maximum term of 20 years from the date an application is filed. +We have four United States patents and numerous foreign patents for the OraSure ® and Intercept ® collection devices and technology relating to oral fluid collection, containers for oral fluids, methods to test oral fluid, formulations for the manufacture of synthetic oral fluid, and methods to control the volume of oral fluid collected and dispersed. The U.S. patents expire from May 2021 to December 2026. We have also applied for additional patents, in both the United States and certain foreign countries, on such products and technology. +14 +We have one United States patent for our OraQuick ® platform expiring in 2028 , as well as corresponding related international patents. We also have patent applications pending internationally. We have two pending patents in the United States for our COVID-19 Rapid Antigen Self-Test and we expect to file additional patent applications for this product in certain international markets. +We hold, through our subsidiary, DNAG, twenty-two granted United States patents and numerous foreign patents issued for compositions, methods and apparatuses for the collection, stabilization, transportation and storage of nucleic acids (DNA and RNA) from oral fluid and other bodily fluids and tissues. These patents expire from February 2022 through March 2035. +We hold through our subsidiary, Novosanis, one granted United States patents and numerous foreign patents covering a medical device for capturing a predetermined volume of first void urine. This patent expires in September 2033. +Our subsidiary, Diversigen, has licensed one United States patent and several foreign patent applications from the University of Minnesota for analytical standards to detect and/or measure sampling, processing, and/or amplification errors in a biological samples containing polynucleotide molecules. This license also covers certain software and know-how related to laboratory and bioinformatics procedures and processes. Diversigen has also licensed certain know-how and database assets from the Baylor College of Medicine related to laboratory processes for microbiome and metagenomics services. +We require our employees, consultants, outside collaborators and other advisors to execute confidentiality agreements upon the commencement of employment or consulting relationships with us. These agreements provide that all confidential information developed by or made known to the individual during the course of the individual’s relationship with us is to be kept confidential and not disclosed to third parties except in specific circumstances. In the case of employees and certain consultants, the agreements also provide that all inventions conceived by the individual during his or her tenure with us or the performance by the consultant of services for us will be our exclusive property. +We own rights to trademarks and service marks that we believe are necessary to conduct our business as currently operated. In the United States, we own a number of trademarks, including the OraSure ® , Intercept ® , Intercept i2 ® , OraQuick ® , OraQuick ADVANCE ® , OraSure QuickFlu ® , Q.E.D. ® , Oragene ® , DNA Genotek TM , OMNImet TM , ORAcollect ® , OMNIgene ® , Diversigen ® , Colli-Pee ® , AUTO-LYTE ® , prepIT ® and Hemagene ® trademarks. We also own many of these marks and others in several foreign countries and we are pursuing registration of several other trademarks. +Although important, the issuance of a patent or existence of trademark or trade secret protection does not in itself ensure the success of our business. Competitors may be able to produce products competing with our patented products without infringing our patent rights. Issuance of a patent in one country generally does not prevent manufacture or sale of the patented product in other countries. The issuance of a patent is not conclusive as to validity or as to the enforceable scope of the patent. The validity or enforceability of a patent or trademark can be challenged by litigation after its issuance or registration. If the outcome of such litigation is adverse to the owner of the patent, the owner’s rights could be diminished or withdrawn. Trade secret protection does not prevent independent discovery and exploitation of the secret product or technique. +Government Regulation +General +Most of our products are regulated by the FDA, along with other federal, state and local agencies and comparable regulatory bodies in other countries. This regulated environment governs almost all aspects of development, production and marketing, including product design and testing, authorizations to market, labeling, advertising and promotion, manufacturing, distribution, post-market surveillance and reporting, and recordkeeping. We believe that our products and procedures are in material compliance with all applicable regulations, but the regulations regarding the manufacture and sale of our products may be unclear and are subject to change. We cannot predict the effect, if any, that these changes might have on our business, financial condition or results of operations. +Many of our FDA-regulated products require some form of review and action by the FDA before they can be marketed in the United States. After approval or clearance by the FDA, we must continue to comply with other FDA requirements applicable to marketed products and are subject to periodic inspections by the FDA and other regulatory bodies. Both before and after approval or clearance, failure to comply with the FDA’s requirements can lead to significant penalties or could disrupt our ability to manufacture and sell these products. In addition, the FDA could refuse permission to obtain certificates needed to export our products if the agency determines that we are not in compliance. +15 +Domestic Regulation +Most of our products are regulated in the United States as in vitro diagnostic and medical devices. In the United States, devices are classified into three groups based on risk: class I (lowest risk), class II (moderate risk), and class III (highest risk). The classification of a device determines the level of regulation applicable to the device: class I devices are subject only to the general controls that are applicable to all regulated devices; class II devices are subject to both general controls and special controls, which are specific to the type of device; and class III devices are subject to general controls and any other controls that are needed to provide reasonable assurance of the safety and effectiveness of the specific device. +The classification of the device also influences the type of premarket submission that is required before the device can be marketed. Some low risk devices (including many class I and some class II devices) may be placed on the market without any premarket submission. Such devices often are referred to as “exempt” or “510(k)-exempt.” Most devices, however, require some form of premarket submission prior to marketing. There are several mechanisms by which such devices can be placed on the market in the United States, including 510(k)-clearance, de novo classification, premarket approval, or emergency use authorization. +Many class II devices and some class I devices may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act. To obtain this clearance from the FDA, the manufacturer must submit to the FDA a premarket notification that it intends to begin marketing the product, and show that the product is substantially equivalent to another legally marketed predicate device (i.e., a device that has been cleared through the 510(k) process; a device that was legally marketed prior to May 28, 1976; a device that has been downclassified by the FDA; or a device that the FDA previously has determined to be exempt from the 510(k) process). To be substantially equivalent, an applicant must show that when compared to a predicate, the new device has the same intended use and same technology, or if different technology, that the new device is as safe and effective as the predicate and does not raise different questions of safety and effectiveness. In all cases, data from some form of performance testing is required and in some cases, the submission must include data from human clinical studies. An applicant must submit a 510(k) notification at least 90 days before commercial distribution of the product commences. Marketing may only commence when the FDA issues a clearance letter finding that the new device is substantially equivalent to the predicate device. The standards and data requirements necessary for the clearance of a new device may be unclear or may be subject to change. Although FDA clearance usually takes from four to twelve months, in some cases more than a year may be required before clearance is obtained, if at all. +If the device does not qualify for the 510(k) procedure, either because there is no existing predicate device, it is not substantially equivalent to a legally marketed predicate device or because it is classified by the FDA as a class III device, the FDA must approve either a request for de novo classification or a premarket approval application (“PMA”) before marketing can begin. A de novo classification is an alternate pathway to classify novel devices of low to moderate risk for which no substantially equivalent predicate device exists into class I or class II. The FDA’s goal is to decide a de novo request in 150 days from the time the request is received, although it can take longer. +PMAs generally are required for class III devices, i.e., high risk devices, and must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness for the intended use(s) of the device. A PMA is typically a complex submission, supported by valid scientific evidence, including the results of preclinical and clinical studies, usability data, detailed information about the manufacturing process for the device, and other data and information. Preparing a PMA is a resource-intensive and time-consuming process. Once a PMA has been submitted, the FDA is required to review the submission within 180 days. However, the FDA’s review may be, and often is, much longer, in many cases requiring one to three years or more, and may include requests for additional data, review by an independent panel of experts, and facility inspections before approval is granted, if at all. +If the FDA approves the PMA, it may place restrictions on the device. If the FDA’s evaluation of the PMA or the manufacturing facility is not favorable, the FDA may deny approval of the PMA application or issue a “not approvable” letter. The FDA may also require additional clinical trials, which can delay the PMA approval process by several years or prevent a PMA approval from being obtained. +If the FDA discovers that an applicant has submitted false or misleading information in any application or notification, the FDA may take action against the applicant and its employees or refuse to review submissions until certain requirements are met pursuant to its Application Integrity Policy. Delays in receipt of or failure to receive such clearances or approvals, the loss of previously received clearances or approvals, or the failure to comply with existing or future regulatory requirements could have a material adverse effect on our business, financial condition and results of operations. +Another option for marketing a product in the U.S. is through an EUA. FDA may grant an EUA application for a product if the Secretary of Health and Human Services declares that circumstances exist justifying the authorization of emergency use of certain products. Such declaration may be made following a determination by the Secretary of Health and Human Services that there is a public health emergency, by the Secretary of Homeland Security that there is a domestic emergency, or by the Secretary of Defense +16 +that there is a military emergency, or the declaration may be made if a material threat is identified under a particular provision of the Public Health Service Act. Typically, a diagnostic device may receive EUA-authorization on the basis of analytical and clinical studies that do not satisfy the requirements for clearance or approval. Devices also may be exempt from design controls and other quality requirements. An EUA for a device remains in effect until the Secretary of Health and Human Services, in consultation with the Secretary of Defense, determines that the circumstances justifying emergency use of the device no longer exist, or until the authorized device is approved or cleared. +If there are any modifications made to our marketed devices, a new premarket notification, PMA supplement, or request to change an EUA may be required to be submitted to, and cleared, approved, or authorized by, the FDA, before the modified device may be marketed. A new PMA or a PMA supplement is required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s intended use(s), manufacturing process, manufacturing facility, critical components, labeling and design. Likewise, a new 510(k) clearance is required for any modification that could significantly affect the safety or effectiveness of the device, e.g. a significant change or modification in design, material, chemical composition, energy source, or manufacturing process or a major change or modification in the intended use(s) of the device. +A clinical trial may be required in support of a 510(k) submission and generally is required for a de novo or PMA application. These trials generally require an approved application for an Investigational Device Exemption (“IDE”) and compliance with other IDE requirements, unless the proposed study is deemed to be exempt from the IDE requirements. An IDE application must be supported by appropriate data, such as laboratory testing results, protocols for the proposed investigation, and other information demonstrating that the device is appropriate for use with humans in a clinical study. Clinical trials may begin if the IDE application is approved by the FDA and the appropriate institutional review boards at the clinical trial sites. Submission of an IDE application does not give assurance that the FDA will issue the IDE. If the IDE application is approved, there can be no assurance the FDA will determine that the data derived from the trial(s) support the ultimate approval or clearance of the device or warrant the continuation of clinical trials. An IDE supplement must be submitted to and approved by the FDA before a sponsor or investigator may make a change to the investigational plan in such a way that may affect its scientific soundness, study indication or the rights, safety or welfare of human subjects. The trial must also comply with the FDA’s regulations, including the requirement that informed consent be obtained from each subject, and with clinical trial reporting regulations that require submission of information on certain clinical trials to a database maintained by the National Institutes of Health. Even if a trial is completed, the results of clinical testing may not adequately demonstrate the safety and efficacy of the device or may otherwise not be sufficient to obtain FDA clearance to market the product in the United States. If a study meets the requirements for a non-significant risk study, however, it may be eligible for compliance with “abbreviated” IDE requirements, which include a subset of the requirements applicable to significant risk medical device studies. A non-significant risk study also will be considered to have an approved IDE application without such application actually being submitted to FDA. +Some of our products are used for research only or other nonclinical or non-diagnostic purposes. Our molecular collection products are sold to many academic and research institutions for research purposes and our drugs-of-abuse products are sold to laboratories and clinics for forensic or other non-medical uses. The FDA does not currently regulate products used for these purposes, although other state and federal regulatory requirements may apply. +Most devices distributed in the United States must comply with the FDA’s Quality System Regulations (“QSRs”), including current good manufacturing practices. These regulations govern the entire lifecycle of a medical device, including design, manufacture, testing, release, packaging, distribution, documentation and purchasing as well as complaint handling, corrective and preventative actions, and internal auditing. In complying with the QSRs, manufacturers must continue to expend time, money and effort in the area of production, quality, and postmarket surveillance to ensure full compliance. +Companies that market devices are also subject to other post-market and general requirements, including product listing and establishment regulations, which help facilitate FDA inspections and other regulatory action, post-market surveillance requests, restrictions imposed on marketed products, promotional standards and requirements for recordkeeping and reporting of certain adverse reactions and device malfunctions. Device reporting regulations require that manufacturers report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur. +The FDA regularly inspects companies to determine compliance with the QSRs and other post-market requirements. Failure to comply with statutory requirements and the FDA’s regulations can result in an FDA Form 483 (which is issued by the FDA at the conclusion of an inspection when an investigator has observed any conditions that may constitute violations), public warning letters, monetary penalties against a company or its officers and employees, suspension or withdrawal of regulatory approvals, operating restrictions, total or partial suspension of production, injunctions, product recalls, product detentions, refusal to provide export certificates, seizure of products and criminal prosecution. We believe that our facilities and procedures are in material compliance with the FDA’s OSR +17 +regulations and other postmarket requirements, but the regulations are subject to change or may be unclear, and we cannot be sure that FDA investigators will agree with our compliance with the FDA’s postmarket requirements. +The Clinical Laboratory Improvement Amendments of 1988 (“CLIA”) prohibit any facility that conducts laboratory testing on specimens derived from humans from providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings, unless there is in effect for such facility a certificate issued by the U.S. Department of Health and Human Services or an accredited organization, and such certificate is applicable to the category of examination or procedure performed. Tests may be categorized as “waived,” enabling them to be used by laboratories with the lowest level of CLIA oversight if the tests meet certain requirements established under CLIA. We consider the applicability of CLIA requirements in the design and development of our products. We have obtained a waiver of the CLIA requirements for our OraQuick ADVANCE ® rapid HIV-1/2 antibody test, our OraQuick ® HCV rapid antibody test and our Q.E.D. ® alcohol saliva test and may seek similar waivers for certain other products. In addition, the supplier of the OraSure Quick-Flu® test has obtained a CLIA waiver for that product. +The laboratory services provided by our subsidiary, Diversigen, are subject to CLIA and consist of microbiome and metagenomics sequencing, bioinformatics and analysis. Diversigen has recently received a CLIA certificate of registration in Minnesota, and is pursuing accreditation from the College of American Pathologists (CAP). A CLIA certificate of compliance is issued once a state regulator or the Center for Medicare and Medicaid Services determines that the laboratory is compliant with the applicable CLIA requirements. Under CLIA, certain organizations—including CAP—can accredit laboratories performing testing on specimens from human beings or animals, using methodologies and clinical applications within the expertise of the laboratory accreditation program. +Certain of our products may also be affected by state regulations in the United States, which can restrict the use and sale of certain diagnostic products. We are presently working with legislators or regulators in certain of these states in an effort to modify or remove any restrictions affecting our ability to sell products. +Advertising and Promotion +Advertising and promotion of medical devices, in addition to being regulated by the FDA, are also regulated by the Federal Trade Commission (“FTC”) and by other federal and state regulatory and enforcement authorities, including the Department of Justice (“DOJ”), the Office of Inspector General of the Department of Health and Human Services, and various state attorneys general. Although physicians are permitted to exercise medical judgment to use medical devices for indications other than those cleared or approved by the FDA, we may not promote our products for such “off-label” uses and can only market our products for cleared or approved uses. Promotional activities for FDA-regulated products of other companies have also been the subject of enforcement actions brought under healthcare reimbursement laws and consumer protection statutes. In addition, under the federal Lanham Act and similar state laws, competitors and others can initiate litigation relating to advertising claims. If the FDA determines that our promotional materials or training constitute promotion of an uncleared or unapproved use, it could request that we modify our training or promotional materials or subject us to regulatory or enforcement actions, including the issuance of an untitled letter, a notice of violation, a warning letter, injunction, seizure, civil fine or criminal penalties. FTC enforcement actions often result in consent decrees that constrain future actions. DOJ prosecutions can result in significant criminal and civil penalties, including exclusion from the Medicare and Medicaid programs. If an enforcement action is brought by the FDA or FTC, our reputation could be damaged and sales of our products could be impaired. +Import and Export Requirements +Products for export from the United States are subject to foreign countries’ import requirements and the exporting requirements of the FDA, as applicable. In particular, international sales of medical devices manufactured in the United States that are not approved or cleared by the FDA for use in the United States, or are banned or deviate from lawful performance standards, are subject to FDA export requirements. +Foreign countries often require, among other things, an FDA certificate for products for export, also called a Certificate for Foreign Government (“CFG”). To obtain this certificate from the FDA, the device manufacturer must apply to the FDA. The FDA certifies that the product has been granted clearance or approval in the United States and that the manufacturing facilities were in compliance with QSR regulations at the time of the last FDA inspection. If the FDA determines that our facilities or procedures do not comply with the QSR regulations, it may refuse to provide such certificates until we resolve the issues to the FDA’s satisfaction. Failure to obtain a CFG could inhibit our ability to export our products to countries that require such certificates. +18 +International +We are also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval (or pre-qualification or endorsement) from local regulators in such countries or international public health agencies, such as the World Health Organization, in order to sell products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for U.S. governmental approvals. We generally pursue approval only in those countries that we believe have a significant market opportunity. +The International Organization for Standardization (“ISO”) is a worldwide federation of national standards bodies from some 130 countries, established in 1947. The mission of the ISO is to promote the development of standardization and related activities in the world with a view to facilitating the international exchange of goods and services. ISO 13485 certification indicates that our quality system complies with standards applicable to activities ranging from initial product design and development through production and distribution. +In the European Union (“EU”), products that fall under the scope of the Medical Devices Directive (“MDD”) and the In Vitro Diagnostic Medical Devices Directive (“IVDD”) are not subject to the prior approval of a regulatory authority, but, depending on the class of product, may require prior review by a notified body. Notified bodies are accredited and supervised by national regulatory authorities to conduct conformity assessment procedures of medical devices or other products. Such products must comply with certain essential requirements listed in those directives. ISO certification creates a rebuttable presumption that the product satisfies the applicable requirements. Compliance with these requirements allows us to complete the applicable conformity assessment procedure, involving a notified body where necessary, and to affix the CE mark to our products, without which they may not be placed on the market in the EU. +In addition, the EU has adopted the EU Medical Devices Regulation (the “EU MDR”) and the In Vitro Diagnostic Medical Devices Regulation (the “EU IVDR”), which will repeal and replace the MDD and IVDD. The EU MDR and EU IVDR impose stricter requirements for the marketing and sale of medical devices, including in the area of clinical evaluation requirements, quality systems and post-market surveillance. Manufacturers of currently approved medical devices will have until May 2021 to meet the requirements of the EU MDR and until May 2022 to meet the EU IVDR. Compliance with these regulations may be expensive and time-consuming. Failure to meet these requirements could adversely impact our business in the EU and other regions that tie their product registrations to the EU requirements. We also note that from January 1, 2021, the United Kingdom (“UK”) has introduced a UK-specific route to market for medical devices. Compliance with these requirements may add further complexities to our international strategy. +We must also comply with certain registration and licensing requirements as dictated by Health Canada, prior to commencing sales in Canada. We have completed this process for several of our current products and may do so with respect to other products in the future. In addition, Canadian law requires manufacturers of medical devices to have a quality management system that meets various ISO requirements in order to obtain a license to sell their devices in Canada. Health Canada also requires all companies that market Class II, Class III and Class IV products in Canada to be certified as part of the Medical Device Single Audit Program (MDSAP). We received this certification for our Diagnostics segment (previously named “OSUR”) in June 2019. +We have obtained WHO pre-qualification for our OraQuick ® HIV Self-Test and OraQuick ® HCV test and we will likely seek WHO pre-qualification or endorsement for certain other products sold into international markets. +Anti-Kickback and Other Fraud and Abuse Laws +The Federal Anti-Kickback Statute prohibits the knowing and willful offer, payment, solicitation, or receipt of any form of remuneration in return for, or to induce: +• +The referral of an individual to a person for the furnishing or arranging for the furnishing of items or services reimbursable under Medicare, Medicaid or other governmental healthcare programs; or +• +The purchase, lease, or order of, or the arrangement or recommendation of the purchasing, leasing, or ordering of any item or service reimbursable under Medicare, Medicaid, or other governmental healthcare programs. +Our products are or may be purchased by customers that will seek or receive reimbursement under Medicare, Medicaid or other governmental healthcare programs. Noncompliance with the Federal Anti-Kickback Statute can result in exclusion from Medicare, Medicaid or other governmental healthcare programs, and/or restrictions on our ability to operate in certain jurisdictions, as well as civil and criminal penalties, any of which could have an adverse effect on our business and results of operations. +19 +The False Claims Act (“ FCA ”) , imposes liability on any person or entity who, among other things, knowingly and willfully presents, or causes to be presented, a false or fraudulent claim for payment by a federal health care program, including Medicaid and Medicare. A violation of the Federal Anti-Kickback Statute is considered a violation of the FCA. Some suits filed under the FCA, known as “qui tam” actions, can be brought by a “whistleblower” or “relator” on behalf of the government, and such individuals may share in any amounts paid by the entity to the government in fines or settlement. Manufacturers can be held liable under false claims laws, even if they do not submit +The Federal Civil Monetary Penalties Law prohibits the offering or transferring of remuneration to a Medicare or Medicaid beneficiary that the person knows or should know is likely to influence the beneficiary’s selection of a particular provider, practitioner or supplier of Medicare or Medicaid payable items or services. Noncompliance can result in civil monetary penalties for each wrongful act, assessment of three times the amount claimed for each item or service and exclusion from the Federal healthcare programs. +Many states have also adopted some form of anti-kickback laws and false claims laws. A determination of liability under such laws could result in fines and penalties, restrictions on our ability to operate in these jurisdictions and significant damage to our reputation. +We are also subject to other federal and state laws targeting fraud and abuse in the healthcare industry, including marketing conduct laws, transparency laws, and laws that require us to adopt a compliance program. Taken together, these fraud and abuse laws constrain the sales, marketing and other promotional activities of manufacturers of medical devices by limiting the kinds of financial arrangements, including sales programs, such manufacturers can enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. Violations of these laws may be punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government healthcare programs such as Medicare and Medicaid. These laws and regulations are wide ranging and subject to changing interpretation and application. In recent years, there has been greater scrutiny of marketing practices in the medical device industry which has resulted in several government investigations by various government authorities and the introduction and/or passage of federal and state legislation regulating interactions between medical device manufacturers and healthcare professionals and providers and requiring the disclosure by medical device manufacturers of payments to certain healthcare providers. For example, under the Sunshine Act provisions of the Affordable Care Act, device manufacturers are subject to federal reporting and disclosure requirements with regard to payments or other transfers of value made to health care providers. Reports submitted under the Sunshine Act are placed in a public database. Device manufacturers are required to submit annual reports by March 31 which cover the prior calendar year. To be in compliance with such disclosure laws, we have implemented necessary systems to accurately track gifts and other payments. +We have implemented a written Policy on Interactions with Health Care Professionals, which is based on the Code of Conduct for Interactions with Health Care Professionals promulgated by the Advanced Medical Technology Association, or AdvaMed, a leading trade association representing medical device manufacturers. The Policy applies to all employees and is intended to comply with applicable state and federal laws, regulations and government guidance. The Policy addresses interactions related to sales and marketing practices, research and development, product training and education, grants and charitable contributions, support of third-party educational conferences, and consulting arrangements. While we believe that our practices are in compliance with the Anti-Kickback and other fraud and abuse laws, the standards for compliance with such statutes can be unclear and subject to change. +Foreign Corrupt Practices Act and Other Anti-Corruption Laws +The U.S. Foreign Corrupt Practices Act (“FCPA”), to which we are subject, prohibits corporations and individuals from engaging in bribery and corruption when dealing with foreign government officials and foreign political parties. It is illegal to corruptly offer, pay, promise, or authorize the giving of anything of value to any officer or employee of a foreign government or public international organization, political party, political party official, or political candidate, in an attempt to obtain or retain business or to otherwise improperly influence a person working in an official capacity on behalf of a foreign government or public international organization. Our present and future business has and will continue to be subject to the FCPA and various other laws, rules and/or regulations applicable to us as a result of our international sales. We also are subject to the FCPA’s accounting provisions, which require us to keep accurate books and records and to maintain a system of internal accounting controls sufficient to assure management’s control, authority, and responsibility over the company's assets. The failure to comply with the FCPA and similar laws could result in civil or criminal sanctions or other adverse consequences. +The laws to which we are subject as a result of our international sales also include the U.K. Bribery Act (the “Bribery Act”), which proscribes giving and receiving bribes in the public and private sectors, bribing a foreign public official, and failing to have adequate procedures to prevent employees and other agents from giving bribes. U.S. companies that conduct business in the United Kingdom generally will be subject to the Bribery Act. Penalties under the Bribery Act include potentially unlimited fines for companies and criminal sanctions for corporate officers under certain circumstances. +20 +Environmental Regulation +Because of the nature of our current and proposed research, development, and manufacturing processes, we are subject to stringent federal, state and local laws, rules, regulations and policies governing the use, generation, manufacture, storage, air emission, effluent discharge and handling and disposal of solid wastes, hazardous materials and hazardous wastes. Products that we sell in Europe are subject to regulation in European Union, or EU, markets under the Directive on the Restriction of the Use of Certain Hazardous Substances (“RoHS”). RoHS prohibits companies from selling electrical and electronic equipment, such as electronic medical devices, that contain certain hazardous materials, including lead, mercury, cadmium, chromium, polybrominated biphenyls and polybrominated diphenyl ethers, in the EU Member States. In addition, the EU’s Regulation on the Registration, Evaluation, Authorization, and Restriction of Chemicals (“REACH”) imposes severe restrictions and requirements on companies marketing devices in the EU. Among other things, REACH requires companies to obtain prior authorization to use substances of very high concern that are listed for authorization, and imposes bans on the marketing of products that contain specifically listed hazardous substances. Companies marketing medical devices in the EU may also be subject to expensive waste take back obligations under the EU Directive on Waste Electrical and Electronic Directive, the Packaging and Packaging Waste Directive, and the Batteries Directive. +Future environmental laws, rules, regulations or policies may require us to alter our manufacturing processes, thereby increasing our manufacturing costs, or may impose other additional obligations on us or our products. We believe that our products and manufacturing processes at our facilities comply in all material respects with applicable environmental laws and worker health and safety laws; however, the risk of environmental liabilities cannot be completely eliminated. +The foregoing discussion of our business should be read in conjunction with the consolidated financial statements and accompanying notes included in Item 15 of this Annual Report. +21 \ No newline at end of file diff --git a/raw/filings/0001116463/2020/0001564590-21-009887/item13.txt b/raw/filings/0001116463/2020/0001564590-21-009887/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..c96a0ed33d20ebd888a868c0fdd44d190d521f6d --- /dev/null +++ b/raw/filings/0001116463/2020/0001564590-21-009887/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. +Certain Relationships and Related Transactions, and Director Independence. +The information required by this Item is incorporated by reference to the information under the captions “Transactions with Related Persons” and “Corporate Governance - Director Independence” in the Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0001116463/2020/0001564590-21-009887/item9a.txt b/raw/filings/0001116463/2020/0001564590-21-009887/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b1024f8f9c3e9609442571bb695f0b27fad27e4e --- /dev/null +++ b/raw/filings/0001116463/2020/0001564590-21-009887/item9a.txt @@ -0,0 +1,29 @@ +ITEM 9A. +Controls and Procedures. +(a) Evaluation of Disclosure Controls and Procedures . +The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of December 31, 2020. Based on that evaluation, the Company’s management, including such officers, concluded that as of December 31, 2020 the Company’s disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. +(b) Management’s Report on Internal Control Over Financial Reporting. +The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of the Company’s management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework, our management concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles as of December 31, 2020. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +The Company acquired UrSure, Inc. during 2020, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2020, the acquired company representing approximately 1.7% of total assets and 0.5% of total revenues of the Company as of and for the year ended December 31, 2020. Management plans to fully integrate the operations of these businesses into the assessment of the effectiveness of the Company’s internal control over financial reporting in 2021. +The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included below. +(c) Changes in Internal Control Over Financial Reporting . +There were no changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +(d) Report of Independent Registered Public Accounting Firm . +To the Stockholders and Board of Directors +OraSure Technologies, Inc.: +Opinion on Internal Control Over Financial Reporting +We have audited OraSure Technologies, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended +62 +December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated March 1, 2021 expressed an unqualified opinion on those consolidated financial statements. +The Company acquired UrSure, Inc. during 2020, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2020, UrSure, Inc.’s internal control over financial reporting associated with approximately 1.7% of total assets and 0.5% of total revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2020. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of UrSure, Inc. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Philadelphia, Pennsylvania +March 1, 2021 \ No newline at end of file diff --git a/raw/filings/0001116463/2020/0001564590-21-009887/rp_note.txt b/raw/filings/0001116463/2020/0001564590-21-009887/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/filing.txt b/raw/filings/0001520006/2014/0001520006-15-000008/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..5dd76ff28d477c6012ce0c695172a1e1ca921edd --- /dev/null +++ b/raw/filings/0001520006/2014/0001520006-15-000008/filing.txt @@ -0,0 +1,6683 @@ +10-K +1 +mtdr10-k12312014.htm +10-K +MTDR 10-K 12.31.2014 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2014 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission file number 001-34574 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas +27-4662601 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 +Dallas, Texas 75240 +75240 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: (972) 371-5200 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ý No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +ý +Accelerated filer +¨ +Non-accelerated filer +¨ +(Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ¨ No ý +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,962,490,009 . +As of February 27, 2015 , there were 76,728,605 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2015 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +BUSINESS +3 +I TEM 1A. +RISK FACTORS +30 +I TEM 1B. +UNRESOLVED STAFF COMMENTS +48 +I TEM 2. +PROPERTIES +48 +I TEM 3. +LEGAL PROCEEDINGS +48 +I TEM 4. +MINE SAFETY DISCLOSURES +48 +PART II +I TEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +49 +I TEM 6. +SELECTED FINANCIAL DATA +53 +I TEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +55 +I TEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +74 +I TEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +76 +I TEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +76 +I TEM 9A. +CONTROLS AND PROCEDURES +77 +I TEM 9B. +OTHER INFORMATION +79 +PART III +I TEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +79 +I TEM 11. +EXECUTIVE COMPENSATION +79 +I TEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +79 +I TEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +79 +I TEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +79 +PART IV +I TEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +80 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: the integration of the assets, employees and operations of Harvey E. Yates Company following its merger with one of our wholly-owned subsidiaries on February 27, 2015, changes in oil or natural gas prices, the success of our drilling program, the timing of planned capital expenditures, sufficient cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, availability of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report on Form 10-K and in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• +our business strategy; +• +our reserves; +• +our technology; +• +our cash flows and liquidity; +• +our financial strategy, budget, projections and operating results; +• +our oil and natural gas realized prices; +• +the timing and amount of future production of oil and natural gas; +• +the availability of drilling and production equipment; +• +the availability of oil field labor; +• +the amount, nature and timing of capital expenditures, including future exploration and development costs; +• +the availability and terms of capital; +• +our drilling of wells; +• +government regulation and taxation of the oil and natural gas industry; +• +our marketing of oil and natural gas; +• +our exploitation projects or property acquisitions; +• +the merger of our wholly-owned subsidiary with Harvey E. Yates Company; +• +our costs of exploiting and developing our properties and conducting other operations; +• +general economic conditions; +• +competition in the oil and natural gas industry; +• +the effectiveness of our risk management and hedging activities; +• +environmental liabilities; +• +counterparty credit risk; +• +developments in oil-producing and natural gas-producing countries; +• +our future operating results; +• +estimated future reserves and the present value thereof; and +• +our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such +1 +Table of Contents +forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +2 +Table of Contents +PART I +Item 1. Business. +In this Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. +Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering. +For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Permian Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• maintain our financial discipline; and +• pursue opportunistic acquisitions. +The successful execution of our business strategies in 2014 led to significant increases in our oil and natural gas revenues and Adjusted EBITDA, oil and natural gas production and proved oil and natural gas reserves, and the associated increase in the PV-10 of our proved oil and natural gas reserves. We also significantly increased our leasehold position in the Permian Basin and added to our acreage position in the Eagle Ford shale. Adjusted EBITDA and PV-10 are non-GAAP financial measures. For a definition of such terms and a reconciliation to the most directly comparable GAAP financial measures, see “Selected Financial Data — Non-GAAP Financial Measures” and “—Estimated Proved Reserves.” +3 +Table of Contents +2014 Highlights +Increased Oil and Natural Gas Revenues and Adjusted EBITDA +Our oil and natural gas revenues for the year ended December 31, 2014 were the highest achieved in any fiscal year in the Company’s history. Our oil and natural gas revenues increased $98.7 million to $367.7 million in 2014 , which represents an increase of 37% from 2013. This revenue increase was primarily driven by a significant increase in our oil and natural gas production in 2014 . Our Adjusted EBITDA of $262.9 million for 2014 was an increase of 37% , as compared to our Adjusted EBITDA of $191.8 million for 2013. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2014 , we achieved record oil, natural gas and average daily oil equivalent production. In 2014 , we produced 3.3 million barrels of oil, an increase of 56% , as compared to 2.1 million barrels of oil produced in 2013. We also produced 15.3 Bcf of natural gas, an increase of 18% from 12.9 Bcf of natural gas produced in 2013. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, an increase of 37% , as compared to 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, for the year ended December 31, 2013 . The increase in oil production was primarily attributable to our ongoing development activities in the Eagle Ford shale, as well as better-than-expected initial production contributions from wells drilled in the Permian Basin during 2014 . We achieved this increased oil production despite having as much as 15% to 20% of our production capacity shut in at various times during 2014 while offsetting wells were being drilled and completed and pipeline connections were being made. The increase in natural gas production was primarily attributable to initial production contributions from wells drilled in the Permian Basin, as well as non-operated Haynesville shale wells drilled on our Elm Grove properties in Northwest Louisiana. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2014 , as compared to 50% for the year ended December 31, 2013 and 37% for the year ended December 31, 2012. +Increased Oil and Natural Gas Reserves +At December 31, 2014 , our estimated total proved oil and natural gas reserves were 68.7 million BOE, including 24.2 million Bbl of oil and 267.1 Bcf of natural gas, which is an increase of 33% from December 31, 2013 . The associated PV-10 of our estimated total proved oil and natural gas reserves increased 59% to $1.04 billion at December 31, 2014 from $655.2 million at December 31, 2013 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 48% to 24.2 million Bbl at December 31, 2014 from 16.4 million Bbl at December 31, 2013 . This growth in oil reserves was primarily attributable to our drilling programs in both the Eagle Ford shale and the Permian Basin during 2014 . Our proved natural gas reserves increased 26% to 267.1 Bcf at December 31, 2014 from 212.2 Bcf at December 31, 2013 . This increase in proved natural gas reserves was primarily attributable to our operated drilling activity in the Permian Basin and non-operated drilling activity in the Haynesville shale during 2014. +At December 31, 2014 , proved developed reserves included 14.1 million Bbl of oil and 102.8 Bcf of natural gas, and proved undeveloped reserves included 10.1 million Bbl of oil and 164.3 Bcf of natural gas. Proved developed reserves comprised 45% and proved oil reserves comprised 35% of our total proved oil and natural gas reserves, respectively, at December 31, 2014 . Proved developed reserves comprised 33% of our total reserves and proved oil reserves comprised 32% of our total proved oil and natural gas reserves, respectively, at December 31, 2013 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to manage more effectively operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past three years, and, during 2014 , we began to apply what we learned from the Eagle Ford shale, as well as from our Haynesville shale experience, to the delineation and development of our Permian Basin acreage. +We continued our strong execution in the Eagle Ford shale during 2014, and the Eagle Ford continued to drive our production and revenue growth in 2014. During 2014, 65% of our total daily oil equivalent production, or 10,501 BOE per day, consisting of 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, was produced from the Eagle Ford shale. +4 +Table of Contents +Over the past three years, we have progressed from drilling Eagle Ford wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In 2014, approximately 90% of our Eagle Ford wells were drilled in multi-well batch mode using drilling rigs equipped with a “walking” package, and as a result, we continued to improve both drilling times and costs. Recent wells drilled on our western Eagle Ford acreage in La Salle County, Texas had drilling times from spud to total depth of seven to 10 days per well. Average drilling and completions costs in this area have been reduced to $5.5 to $6.5 million per well. On our central Eagle Ford acreage in Karnes County, Texas, significant drilling improvements, including the use of the “walking” rig, were made during 2014 that reduced drilling times by several days, especially during the second half of 2014. We anticipate that the combination of further operational improvements and service cost reductions may yield drilling and completion costs at or below $6.0 million on wells drilled on our central Eagle Ford acreage during 2015. +During 2014, we made further improvements to our Eagle Ford fracture treatment design, with the goal of developing a treatment design specific to wells developed on 40- to 50-acre spacing. The treatments were designed to create higher fracture conductivity closer to the wellbore, more consistent fracture geometry and more overall fractures. We believe that we achieved these design objectives by (1) increasing the fluid volumes pumped to 40 Bbl per foot and the total proppant volumes pumped to 2,000 pounds per foot of completed lateral length or more, (2) tightening the perforation cluster spacing and (3) further modifying the perforation geometry. These “Generation 7” fracture treatments are typically resulting in significant improvements in initial well productivity and overall well performance for our Eagle Ford wells as compared to earlier generation fracture treatment designs using less fluid and proppant and different perforation and cluster geometries. We also believe that initiating the use of gas lift early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. In addition, as our development program matured in 2014, most of our newly completed Eagle Ford wells were able to use existing tank batteries and facilities, resulting in significant cost savings as compared to the need to construct new facilities in previous years. +We substantially increased our acreage position in the Permian Basin during 2014, and at December 31, 2014, we held approximately 92,700 gross (66,100 net) acres primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We also continued the exploration and delineation of our Permian Basin acreage, operating one to two drilling rigs on our acreage there in 2014 and testing six different Bone Spring and Wolfcamp target intervals. The initial performance of most of the wells we have drilled and completed thus far in our three main prospect areas—the Wolf prospect area in Loving County, Texas, the Ranger prospect area in Lea County, New Mexico and the Rustler Breaks prospect area in Eddy County, New Mexico—have exceeded our expectations. As a result, our Permian Basin properties are becoming an increasingly important component of our asset portfolio, and the Permian Basin will be our primary area of focus in 2015. Our average daily oil equivalent production from the Permian Basin grew 10-fold from 260 BOE per day in the fourth quarter of 2013 to 2,600 BOE per day in the fourth quarter of 2014, comprising 11% of our total oil equivalent production for all of 2014. We expect our Permian Basin production to increase throughout 2015 as we continue the delineation and development of these properties. +We did not drill any operated Haynesville shale wells during 2014, but we did participate in a number of non-operated wells drilled in the Haynesville shale in Northwest Louisiana. The most impactful were the Haynesville wells drilled and completed by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove properties in southern Caddo Parish. In 2014, Chesapeake completed and placed on production 14 gross wells, comprising 3.3 wells net to Matador’s working interest. These wells had initial production rates ranging from 8 to 14 MMcf of natural gas per day (gross) and estimated ultimate recoveries of 8 to 12 Bcf per well. As these wells were placed on production in 2014, our Haynesville natural gas production grew more than three-fold from 11.1 MMcf per day in the fourth quarter of 2013 to approximately 35.0 MMcf per day in the fourth quarter of 2014. In January 2015, Chesapeake completed and placed on production an additional three gross (0.5 net) wells at Elm Grove. As a result, our Haynesville natural gas production grew to over 50 MMcf of natural gas per day as of February 27, 2015. +Acreage Acquisitions +During 2014 , we acquired approximately 29,300 gross ( 21,800 net) additional acres in the Permian Basin in Southeast New Mexico and West Texas. These acreage acquisitions brought our total Permian Basin acreage position to approximately 92,700 gross (66,100 net) acres as of December 31, 2014 . Between January 1 and December 31, 2014 , we also acquired approximately 3,200 gross ( 3,000 net) acres in the Eagle Ford shale play in South Texas. +As noted below in “— Recent Developments”, in January 2015, we entered into a definitive agreement pursuant to which one of our wholly-owned subsidiaries would merge with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico owned by HEYCO with our Delaware Basin operations (the “HEYCO Merger”). The HEYCO Merger included approximately 58,600 gross (18,200 net) acres. Upon the closing of the HEYCO Merger on February 27, 2015, our Permian Basin acreage position increased to approximately 152,400 gross ( 85,400 net) acres. +5 +Table of Contents +Issuance of Common Stock +On May 29, 2014, we completed a public offering of 7,500,000 shares of our common stock. After deducting direct offering costs totaling approximately $0.6 million , we received net proceeds of approximately $181.3 million . We used a portion of the net proceeds to repay $180.0 million in outstanding borrowings under our third amended and restated credit agreement (the “Credit Agreement”), which amounts were subsequently reborrowed in accordance with the terms of that facility. The remaining $1.3 million of the offering net proceeds was used to fund working capital requirements. +Recent Developments +On January 19, 2015, we entered into a definitive agreement pursuant to which one of our wholly-owned subsidiaries would merge with HEYCO, combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico owned by HEYCO with our Delaware Basin operations. The HEYCO Merger closed on February 27, 2015. As consideration for the HEYCO Merger, we paid approximately $21.6 million in cash, assumed debt obligations of approximately $12.0 million and issued 3,300,000 shares of the Company’s common stock and 150,000 shares of a new series of the Company’s convertible preferred stock to HEYCO Energy Group, Inc. In addition, we paid an additional $3.0 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. Pursuant to the terms of the merger agreement, 125,000 of the 150,000 shares of Series A Preferred Stock (as defined below) issued upon the closing of the HEYCO Merger were placed into escrow to satisfy post-closing adjustments to the merger consideration for any title or environmental defects on the assets we added. +As part of the consideration for the acquisition, we issued 150,000 shares of Series A Convertible Preferred Stock (the “Series A Preferred Stock”). Each share of Series A Preferred Stock is entitled to ten votes on each matter submitted to our shareholders for vote. The holders of Series A Preferred Stock will vote, on an as-converted basis, together with the holders of common stock as a single class, except with respect to matters that would adversely affect the holders of Series A Preferred Stock as compared to the holders of common stock, in which case the holders of Series A Preferred Stock will vote as a separate class. Beginning on August 27, 2015 and until such time as the Series A Preferred Stock is converted to common stock, the holders will be entitled to a quarterly dividend of $1.80 per share. The private placement of the Series A Preferred Stock and the common stock issued in connection with the HEYCO Merger was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. +Each share of Series A Preferred Stock will automatically convert into ten shares of our common stock, subject to customary anti-dilution adjustments, upon the vote and approval by our shareholders of an amendment to our Amended and Restated Certificate of Formation to increase the number of shares of authorized common stock (the “Charter Amendment”). On February 25, 2015, we filed a definitive proxy statement with the Securities and Exchange Commission and began mailing to our shareholders such proxy materials related to a special meeting of shareholders to be held on April 2, 2015 at 9:30 a.m., Central Time, for the purpose of approving the Charter Amendment. All shareholders of record as of the close of business on February 18, 2015 will be entitled to vote at the special meeting. +As part of the merger consideration, one of our wholly-owned subsidiaries, MRC Delaware Resources, LLC (“MRC Delaware”), assumed approximately $12.0 million of HEYCO’s indebtedness (the “Assumed Indebtedness”). Such Assumed Indebtedness is evidenced by a loan agreement and a promissory note executed by MRC Delaware in favor of PlainsCapital Bank (“PlainsCapital”) in the principal amount of $12,500,000. Outstanding borrowings are secured by mortgages on substantially all of the oil and natural gas properties held by MRC Delaware after the HEYCO Merger and are subject to a borrowing base of approximately $12.0 million. The principal and interest under the promissory note are due and payable on July 24, 2015 and outstanding borrowings under the promissory note bear interest at a variable annual rate equal to the prime rate, but in no event less than 3.25%. The Company executed a guaranty (the “Guaranty”) pursuant to which the Company has agreed to guarantee MRC Delaware’s prompt, complete and full payment of the principal and interest and other fees and obligations relating to the Assumed Indebtedness. In addition, the Company has agreed to comply with a provision of the loan agreement governing the Assumed Indebtedness that sets forth a funded debt to EBITDA (defined as net income before interest, taxes, depletion, depreciation, intangible drilling costs and amortization) ratio covenant, which is defined as total funded debt outstanding for the Company and its consolidated subsidiaries divided by a rolling four quarter EBITDA calculation for the Company and its consolidated subsidiaries, of 4.25 or less. A failure by the Company to meet the requirements of such covenant, or a failure to otherwise comply with the payment guaranty provisions set forth in the Guaranty, will constitute an event of default under our Credit Agreement. +In connection with the HEYCO Merger, we entered into a registration rights agreement with HEYCO Energy Group, Inc., pursuant to which we will be required, upon request from HEYCO Energy Group, Inc. at any time on or after February 27, 2016, to file and maintain a shelf registration statement with respect to the resale of the shares of common stock issued as consideration for the HEYCO Merger and upon conversion of the Series A Preferred Stock, respectively, and to provide piggyback registration rights for such shares of common stock. +6 +Table of Contents +As noted above, the HEYCO Merger added approximately 58,600 gross (18,200 net) acres in the Delaware Basin in Lea and Eddy Counties, New Mexico, strategically located between our existing acreage in the Ranger and Rustler Breaks prospect areas. Over 95% of the HEYCO acreage position consists of state and federal leases, most with favorable net revenue interests greater than 80% and some as high as 87.5%. Essentially all of the acreage is held by production from existing wells and production units. +Principal Areas of Interest +Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Eagle Ford shale play in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas and the Haynesville shale play in Northwest Louisiana. During 2014 , we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin as we sought to continue to increase our oil production and reserves. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2014 , essentially all of our efforts were focused on unconventional plays. +At December 31, 2014 , our principal areas of interest consisted of the Eagle Ford shale play in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where we are testing the Meade Peak shale. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2014 : +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +South Texas: +Eagle Ford (4) +39,871 +29,686 +117 +99.2 +278 +240.4 +22,257 +71.8 +10,501 +NW Louisiana/E Texas: +Haynesville +21,295 +13,571 +183 +16.8 +471 +111.9 +32,183 +30.0 +3,290 +Cotton Valley (5) +22,362 +19,748 +97 +62.4 +71 +50.1 +1,223 +100.0 +501 +Area Total (6) +27,251 +24,396 +280 +79.2 +542 +162.0 +33,406 +32.6 +3,791 +Permian Basin: +SE New Mexico, West Texas (7) +92,682 +66,076 +31 +19.2 +1,445 +959.5 +13,030 +33.1 +1,790 +Other: +Wyoming, Utah, Idaho +75,674 +35,732 +— +— +— +— +— +— +— +Total +235,478 +155,890 +428 +197.6 +2,265 +1,361.9 +68,693 +45.4 +16,082 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2014 . The total net engineered drilling locations is calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2014 , these engineered drilling locations included 40 gross (32.6 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford, 19 gross (15.6 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Permian Basin and 127 gross (20.6 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formation at December 31, 2014 . +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes two wells producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(5) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(6) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +(7) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware and Avalon plays on our acreage in the Permian Basin at December 31, 2014 . +7 +Table of Contents +We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, BHP Billiton and others. At December 31, 2014 , we were the operator for over 90% of our Eagle Ford acreage and approximately two-thirds of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. At December 31, 2014 , we also operated the majority of our acreage in the Permian Basin in Southeast New Mexico and West Texas, as well as all of our acreage in Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interests are often relatively small, particularly in the Haynesville shale. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2014 , our properties included approximately 39,900 gross (29,700 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 77% of our Eagle Ford acreage was held by production at December 31, 2014 , and approximately 96% of our Eagle Ford acreage was either held by production at December 31, 2014 or not burdened by lease expirations before 2016 . During the year ended December 31, 2014 , we acquired approximately 3,200 gross ( 3,000 net) acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This acreage more than replaced the acreage upon which we drilled and established oil and natural gas production and reserves in the Eagle Ford during 2014 . +At December 31, 2014 , we had 117 gross ( 99.2 net) wells producing from the Eagle Ford shale in South Texas. We had drilled and completed a total of 97 gross (93.2 net) Eagle Ford wells on our operated properties, and we had also participated in 20 gross (6.0 net) Eagle Ford wells with co-working interest owners on certain of our non-operated Eagle Ford properties. During 2014 , approximately 56% of our total capital expenditures of $610.4 million were directed to our operations in the Eagle Ford shale, as we continued executing our strategy to significantly increase our oil production and oil reserves. As a result of both lower oil and natural gas prices in early 2015 and the fact that, at December 31, 2014 , approximately 96% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2016, we plan to temporarily suspend our Eagle Ford development program after the first quarter of 2015 . We expect to run two operated drilling rigs in the Eagle Ford during the first quarter of 2015, but then do not plan to drill any operated wells in the Eagle Ford for the remainder of the year. We have allocated approximately $90.0 million, or 26%, of our 2015 capital expenditures budget of $350.0 million (excluding capital expenditures associated with the HEYCO Merger) to our anticipated drilling and completion activities in the Eagle Ford, as well as for the acquisition of additional leasehold interests in this area. +During the year ended December 31, 2014 , we completed and began producing oil and natural gas from 44 gross (36.7 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 36 gross (34.5 net) operated and eight gross (2.2 net) non-operated wells. As we completed and began producing oil and natural gas from these wells during 2014 , our Eagle Ford production increased significantly. For the year ended December 31, 2014 , 65% of our total daily oil equivalent production, or 10,501 BOE per day, including 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, was produced from the Eagle Ford shale. The vast majority of our oil production in 2014 and 2013 was attributable to the Eagle Ford shale. The Eagle Ford shale contributed approximately 85% of our daily oil production and approximately 39% of our daily natural gas production during 2014 , as compared to approximately 98% of our daily oil production and approximately 42% of our daily natural gas production during 2013 . During the year ended December 31, 2013 , approximately 70% of our daily oil equivalent production, or 8,225 BOE per day, including 5,748 Bbl of oil per day and 14.9 MMcf of natural gas per day, was +8 +Table of Contents +attributable to the Eagle Ford shale. During the year ended December 31, 2012, only about 8% of our daily oil equivalent production, or 548 BOE per day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past several years reflects our ongoing drilling and completion operations in South Texas. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich natural gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other heavier natural gas liquids components. Our Eagle Ford wells typically yield five to seven gallons of natural gas liquids per Mcf of natural gas produced at the wellhead depending on the specific property. +At December 31, 2014 , approximately 32% of our estimated total proved oil and natural gas reserves, or 22.3 million BOE, was attributable to the Eagle Ford shale, including approximately 16.1 million Bbl of oil and 36.9 Bcf of natural gas. Our total proved reserves attributable to the Eagle Ford shale increased approximately 10% to 22.3 million BOE for the year ended December 31, 2014 , as compared to 20.2 million BOE for the year ended December 31, 2013 . As a result of our drilling and completions schedule in 2014, and particularly our drilling of infill wells on 40- to 50-acre spacing, many of the Eagle Ford wells we drilled during 2014 were identified as proved developed non-producing (“PDNP”) or proved undeveloped (“PUD”) reserves at December 31, 2013 . Our Eagle Ford total proved reserves at December 31, 2014 comprised approximately 67% of our proved oil reserves and 14% of our proved natural gas reserves, as compared to approximately 93% of our proved oil reserves and 14% of our proved natural gas reserves at December 31, 2013 . The PV-10 of our total proved reserves in the Eagle Ford shale was $603.8 million , or approximately 58% of the PV-10 of our total proved reserves of $1.04 billion at December 31, 2014 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +At December 31, 2014 , we have identified 278 gross ( 240.4 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. As a result of the development wells we drilled during 2014, we anticipate the Eagle Ford wells to be drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. While there are some locations that we would choose not to drill with oil prices near $50 per Bbl as they have been in early 2015, almost all of these locations are associated with portions of our acreage that are already held by production at December 31, 2014 or not burdened by near-term lease expirations. As a result, these engineered drilling locations remain available to be developed by us at a future time when commodity prices improve, drilling and completion costs decline further or new technologies are developed that increase the expected recoveries. At December 31, 2014 , these 278 gross (240.4 net) identified drilling locations included only 40 gross (32.6 net) locations to which we have assigned proved undeveloped reserves. +We believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past three years. During this time, we have progressed from drilling wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In August 2013, we began drilling certain wells on our western Eagle Ford acreage in La Salle County, Texas from batch-drilled pads using a drilling rig equipped with a “walking” package, and in April 2014, we began using a “walking” rig on our central Eagle Ford acreage in Karnes and Wilson Counties. As a result, we have improved drilling times and costs in both areas. We have realized drilling cost savings on wells drilled from batch-drilled pads of approximately 20% per foot drilled compared to wells drilled from single-well pads and approximately 10% per foot drilled compared to wells drilled from multi-well pads. As a result of batch mode development and other operational improvements, we estimate that we have saved approximately $600,000 per well on drilling costs, as compared to wells drilled from single-well pads. Our development strategy in 2014 used three wells per batch pad, but the majority of our Eagle Ford wells, which will be drilled in the first quarter of 2015, will be developed with four wells per batch pad. We expect this development approach to yield further incremental cost savings. +During 2014, most wells drilled on our western Eagle Ford acreage in La Salle County, Texas had drilling times from spud to total depth of seven to 10 days per well. Average drilling and completions costs in this area have been reduced to $5.5 to $6.5 million per well. On our central Eagle Ford acreage in Karnes County, Texas, significant drilling improvements, including the use of the “walking” rig, made during 2014 also reduced drilling times by several days, especially during the second half of 2014. We anticipate that the combination of further operational improvements and service cost reductions may yield drilling and completion costs at or below $6.0 million on wells drilled and completed in our central Eagle Ford acreage during 2015. +9 +Table of Contents +During 2014, we also made further improvements to our Eagle Ford fracture treatment design, with the goal of developing a treatment design specific to wells developed on 40- to 50-acre spacing. The treatments were designed to create higher fracture conductivity closer to the wellbore, more consistent fracture geometry and more overall fractures. We believe that we achieved these design objectives by (1) increasing the fluid volumes pumped to 40 Bbl per foot and the total proppant volumes pumped to 2,000 pounds per foot of completed lateral length or more, (2) tightening the perforation cluster spacing and (3) further modifying the perforation geometry. These “Generation 7” fracture treatments are typically resulting in significant improvements in initial well productivity and overall well performance as compared to earlier generation fracture treatment designs using less fluid and proppant and different perforation and cluster geometries. We also believe that initiating the use of gas lift early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. In addition, as our development program matured in 2014, most of our newly completed Eagle Ford wells were able to use existing tank batteries and facilities, resulting in significant cost savings as compared to the need to construct new facilities in previous years. +We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas which are held by production and which we believe may be prospective for the Buda formation. We believe our acreage is located within the extension of a trend where encouraging drilling by other operators has occurred in the Buda just southwest of our leasehold position. We have acquired a 3-D seismic survey over our acreage, and at February 27, 2015 , we were evaluating a series of seismic attributes that are similar to fracture patterns observed in cores from other wells in the area and from our drilling of previous wells on the acreage in 2012 and which are consistent with regional mapping. At December 31, 2014 , we had not drilled any Buda wells nor had we included any Buda locations in our future drilling locations. +Southeast New Mexico and West Texas — Permian Basin +The Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and intense hydraulic fracturing techniques. +In the western part of the Permian Basin (also known as the Delaware Basin), the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are proven to be the source rocks for oil and natural gas produced in the basin. Historically, production has come from the “conventional” reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-interval hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp “A” through “D”. +During 2014 , we acquired an additional 29,300 gross ( 21,800 net) acres in Southeast New Mexico and West Texas, and at December 31, 2014 , our leasehold position in the Permian Basin included approximately 92,700 gross (66,100 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. With the closing of the HEYCO Merger on February 27, 2015, our Permian Basin acreage position increased to approximately 152,400 gross ( 85,400 net) acres. We consider the vast majority of our Permian Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon shale and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. +During the year ended December 31, 2014, we continued the exploration and delineation of our Permian Basin acreage. We completed and began producing oil and natural gas from 11 gross (9.6 net) wells in the Permian Basin, including ten gross (9.5 net) operated wells and one gross (0.1 net) non-operated wells. The ten operated wells tested six different Bone Spring and Wolfcamp intervals. We completed and placed on production five wells in the Wolf prospect area in Loving County, Texas — four wells testing the Wolfcamp “X” sand at the top of the Wolfcamp interval and one well testing the Wolfcamp “A” interval +10 +Table of Contents +below the “X/Y” sands. Four operated wells in the Ranger prospect area in Lea County, New Mexico tested the Second Bone Spring, the Wolfcamp “D” and the Third Bone Spring. One operated well in the Rustler Breaks prospect area in Eddy County, New Mexico tested the Wolfcamp “B” interval. +In the Wolf prospect area in Loving County, Texas, the upper Wolfcamp “X” sand has proven to be highly productive, and the initial wells completed in this prospect continue to perform above our original projections. As of early February 2015, the Dorothy White #1H well, our first well in the Wolf prospect area, had produced 310,000 BOE (66% oil), including 203,000 Bbl of oil and 640 MMcf of natural gas, in just over one year of production and was still producing 450 Bbl of oil and 1.7 MMcf of natural gas per day. Other wells we have drilled near the Dorothy White #1H are similar. As of early February 2015, the Norton Schaub #1H had produced 122,000 BOE (69% oil) in approximately six months of production, including 84,000 Bbl of oil and 228 MMcf of natural gas, and was still producing 500 Bbl of oil per day and 1.6 MMcf of natural gas per day. The Johnson 44-02S-B53 #204H well drilled north of the Dorothy White #1H had produced 117,000 BOE (65% oil), including 75,000 Bbl of oil and 248 MMcf of natural gas, in just four months of production and in early February 2015 was producing 530 Bbl of oil per day and 1.8 MMcf of natural gas per day. By comparison, the Dorothy White #1H produced 110,000 BOE in its first four months of production. At the southern end of the Wolf prospect area, the Arno #1H well was also drilled and completed in the Wolfcamp “X” sand. This well tested 1,110 BOE per day (27% oil), including 300 Bbl of oil and 4.9 MMcf of natural gas per day at a flowing pressure of 4,100 pounds per square inch (“psi”) on a 26/64-inch choke. This well has only recently been placed on production after having been shut in awaiting a pipeline connection and the repair of a county road that was washed out during flooding in this area in late September 2014. In late December 2014, we also tested the Norton Schaub 84-TTT-B33 WF #2010H in the Wolf prospect area. During a 24-hour initial potential test, this well flowed 875 BOE per day (69% oil), including 608 Bbl of oil per day and 1.6 MMcf of natural gas per day at 2,600 psi on a 28/64-inch choke. The Norton Schaub 84-TTT-B33 WF #2010H was our first test of the Wolfcamp “A” interval, a more organically rich portion of the upper Wolfcamp below the “X/Y” sands. This was another encouraging test of a new Wolfcamp bench and indicates the Wolfcamp “A” may be another potential completion target in the upper Wolfcamp. +In the Ranger prospect area in Lea County, New Mexico, our first two Second Bone Spring completions have performed above our original projections for this area. As of early February 2015, the Ranger 33 State Com #1H had produced 184,000 BOE (91% oil) in its first 15 months of production and was still producing almost 200 Bbl of oil per day with gas-lift assist. The Pickard State 20-18-24 #1H, also drilled and completed in the Second Bone Spring, had produced 71,000 BOE (92% oil) in its first six months of production and was producing 330 Bbl of oil per day with gas-lift assist in early February 2015. We installed gas-lift assist on the Ranger 33 State Com #1H well within its first two months of production, and given the early success of the gas-lift assist on that well, the Pickard State 20-18-34 #1H well was also equipped with gas-lift assist within approximately 30 days of being placed on production. The use of gas-lift assist on these wells in the Ranger prospect area is just one example of a transfer of technology and lessons learned from our Eagle Ford development program in South Texas to the Permian Basin. +Also in the Ranger prospect area, we drilled and completed the Pickard State 20-18-34 #2H during 2014. This well was completed in the Wolfcamp “D” bench at approximately 12,000 feet true vertical depth, and we believe it to be the northernmost horizontal completion to date in the Wolfcamp “D” formation in the Delaware Basin. This well flowed 270 BOE per day, including 232 Bbl of oil and 225 Mcf of natural gas per day (86%) oil at 1,150 psi surface pressure during its 24-hour initial potential test. Although the results of the Pickard State 20-18-34 #2H were more modest than our other Permian Basin wells, we were encouraged by the geopressured nature of this horizon, other zones of interest in the well and because this well established the producibility of hydrocarbons from the Wolfcamp “D” interval. Finally, in the Ranger prospect area, the Jim Rolfe 22-18-34 RN #131H was drilled and completed in the Third Bone Spring sand. This well flowed 260 Bbl per day of oil and 102 Mcf of natural gas per day at 560 psi on a 28/64-inch choke during its 24-hour initial potential test. This well has been turned to sales, and we are in the process of evaluating artificial lift for this well. +In the Rustler Breaks prospect area in Eddy County, New Mexico, our first Wolfcamp “B” test, the Rustler Breaks 12-24-27 #1H has also performed better than our original projections for this area. As of early February 2015, this well had produced 134,000 BOE (43% oil) in about nine months of production and was producing about 140 barrels of oil per day and 1.3 MMcf of natural gas per day. +As we completed and began producing oil and natural gas from these wells during 2014 , our Permian Basin production increased significantly. Our average daily oil equivalent production from the Permian Basin grew ten-fold from 260 BOE per day in the fourth quarter of 2013 to 2,600 BOE per day in the fourth quarter of 2014. For the year ended December 31, 2014 , 11% of our daily oil equivalent production, or 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, was produced from the Permian Basin. The Permian Basin contributed approximately 14% of our daily oil production and approximately 7% of our daily natural gas production during 2014 , as compared to only about 1% of our daily oil production and approximately 0.1% of our daily natural gas production during 2013 . During the year ended December 31, 2013 , only about 1% of our daily oil equivalent production, or 84 BOE per day, including 78 Bbl of oil per day and 36 Mcf of natural gas per day, was attributable to the Permian Basin. +11 +Table of Contents +At December 31, 2014 , approximately 19% of our estimated total proved oil and natural gas reserves, or 13.0 million BOE, was attributable to the Permian Basin, including approximately 8.1 million Bbl of oil and 29.9 Bcf of natural gas. Our proved reserves attributable to the Permian Basin increased substantially to 13.0 million BOE for the year ended December 31, 2014 , as compared to 1.4 million BOE for the year ended December 31, 2013 . Our Permian Basin proved reserves at December 31, 2014 comprised approximately 33% of our proved oil reserves and 11% of our proved natural gas reserves, as compared to approximately 7% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2013 . The PV-10 of our proved reserves in the Permian Basin at December 31, 2014 was $246.2 million , or approximately 24% of the PV-10 of our total proved reserves of $1.04 billion . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +At December 31, 2014 , we had identified and engineered 1,445 gross ( 959.5 net) locations for potential future drilling on our Permian Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the Avalon and Delaware formations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Permian Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2014 do not yet include all portions of our acreage position, including the acreage associated with our Twin Lakes prospect area in Lea County, New Mexico or any locations associated with acreage from the HEYCO Merger. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Permian Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2014 , these potential future drilling locations included only 19 gross (15.6 net) locations in the Permian Basin to which we have assigned proved undeveloped reserves. +At December 31, 2014 , we were operating five contracted drilling rigs — two rigs in the Eagle Ford shale in South Texas and three rigs in the Permian Basin in Southeast New Mexico and West Texas. As a result of the sharp decline in commodity prices in recent months, we intend to scale back our drilling program during the first few months of 2015 to two rigs, both operating in the Permian Basin. In December 2014 and January 2015, we took delivery of two state-of-the-art, new-build rigs in the Permian Basin specifically configured for simultaneous operations and built to our specifications. These new rigs have full walking capabilities and high pressure circulating systems and are designed so that drilling operations can be conducted in the Wolfcamp formation while completion operations are performed in the Bone Spring or other intervals and vice versa—i.e., simultaneous drilling and completion operations. We expect the use of these rigs will result in additional operational efficiencies and will reduce the costs associated with our Permian Basin drilling program in 2015 . We have allocated approximately $245.0 million , or approximately 70% of our 2015 capital expenditure budget of $350.0 million (excluding capital expenditures associated with the HEYCO Merger), to our anticipated drilling and completion activities in the Permian Basin, as well as for the acquisition of additional leasehold interests in the area. Our 2015 Permian Basin drilling program will focus on the development of the Wolf prospect area, the further delineation of our Ranger and Rustler Breaks prospect areas and the integration of the HEYCO acreage. +Northwest Louisiana and East Texas +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2014 , although we did participate in the drilling and completion of 46 gross (4.2 net) non-operated Haynesville shale wells. In the first half of 2014, Chesapeake began the process of drilling up to an anticipated 45 gross (8.7 net) Haynesville shale wells on our Elm Grove acreage in southern Caddo Parrish, Louisiana, which we expect to continue through 2017. We retain the right to participate for up to a 25% working interest in all wells drilled on this property with our working interest proportionately reduced to our leasehold position in any individual drilling unit. After notifying us of its intent to conduct this drilling program, Chesapeake began actively drilling these properties during the second quarter of 2014, and had up to five rigs operating on these properties at any one time during 2014. Approximately 7% of our total capital expenditures of $610.4 million were associated with non-operated Haynesville shale wells in 2014, including those wells drilled by Chesapeake. These wells are being drilled and completed in a multi-well batch mode, and as of December 31, 2014 , Chesapeake had completed and placed 14 gross (3.3 net to us) wells on production. We do not plan to drill any operated Haynesville shale wells in 2015 , but we have budgeted capital expenditures of approximately $15.0 million for our anticipated participation in 33 gross (2.3 net) Haynesville shale wells that we anticipate may be drilled or completed and placed on production by other operators on certain of our non-operated properties in 2015 . Certain of these wells were already in progress at December 31, 2014 . The most significant of these non-operated Haynesville shale wells will be 10 gross (1.8 net) wells that we expect to be completed and placed on production by Chesapeake on our Elm Grove acreage in 2015. +At December 31, 2014 , we held approximately 27,300 gross (24,400 net) acres in Northwest Louisiana and East Texas, including 21,300 gross (13,600 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower +12 +Table of Contents +production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,700 gross (6,800 net) acres that we consider to be in the core area of the Haynesville play. +For the year ended December 31, 2014 , approximately 24% of our average daily oil equivalent production, or 3,791 BOE per day, including 17 Bbl of oil per day and 22.6 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 54% of our daily natural gas production, but oil production from these properties comprised only about 0.2% of our daily oil production during 2014 , as compared to approximately 58% of our daily natural gas production and approximately 0.3% of our daily oil production during 2013 . During the year ended December 31, 2013 , approximately 29% of our average daily oil equivalent production, or 3,431 BOE per day, including 17 Bbl of oil per day and 20.5 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2014 , approximately 47% of our daily natural gas production, or 19.7 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 7% , or 2.9 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2013 , approximately 48% of our daily natural gas production, or 17.0 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 10% , or 3.5 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2014 , approximately 47% of our estimated total proved reserves, or 32.2 million BOE, was attributable to the Haynesville shale with another 2% of our proved reserves, or 1.2 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +Although we averaged production of only about 19.7 MMcf of natural gas per day from the Haynesville shale in 2014 , our average daily natural gas production grew over three-fold during the year from almost 11.1 MMcf of natural gas per day in the fourth quarter of 2013 to approximately 35.0 MMcf of natural gas per day in the fourth quarter of 2014. This rapid growth in our Haynesville production was primarily due to the drilling and completion of 14 gross (3.3 net) non-operated Haynesville shale wells drilled by Chesapeake on our Elm Grove properties in Northwest Louisiana. Our Elm Grove properties are in what we believe is the core area of the Haynesville shale, and we anticipate the estimated ultimate recoveries from these wells at 8 to 12 Bcf each. Since January 1, 2015, Chesapeake has completed and placed on production three gross (0.5 net) additional wells. As a result, at February 27, 2015, we were producing over 50 MMcf of natural gas per day from the Haynesville shale. +At December 31, 2014 , we had identified and engineered 471 gross ( 111.9 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 471 gross ( 111.9 net) locations identified for future drilling on our Haynesville acreage, 396 gross (58.0 net) locations have been identified within the 13,700 gross (6,800 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2014 , these potential future drilling locations included 127 gross (20.6 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Haynesville and Middle Bossier Shales +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. +At December 31, 2014 , we had approximately 21,300 gross (13,600 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,700 gross (6,800 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that +13 +Table of Contents +area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2014 . +Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parrish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%. +Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations +Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. +All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2014 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We have identified 71 gross ( 50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2014 and do not plan to drill any of these locations in 2015 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2014 , we held an estimated 12,300 gross (9,800 net) leasehold and mineral acres by existing production in these areas. +Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale +At December 31, 2014 , we held leasehold interests in approximately 75,700 gross (35,700 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are the operator of this prospect. We have drilled and completed one horizontal well on this acreage, but as of December 31, 2014 , we had not established commercial natural gas production on this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2014 . We have no plans to drill on this acreage in 2015. +14 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production data for the years ended December 31, 2014, 2013 and 2012 : +Year Ended December 31, +2014 +2013 +2012 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +3,320 +2,133 +1,214 +Natural gas (Bcf) +15.3 +12.9 +12.5 +Total oil equivalent (MBOE) (1) +5,870 +4,285 +3,294 +Average daily production (BOE/d) (1) +16,082 +11,740 +9,000 +Average Sales Prices: +Oil, with realized derivatives (per Bbl) +$ +88.94 +$ +98.67 +$ +103.55 +Oil, without realized derivatives (per Bbl) +$ +87.37 +$ +99.79 +$ +101.86 +Natural gas, with realized derivatives (per Mcf) +$ +5.06 +$ +4.47 +$ +3.55 +Natural gas, without realized derivatives (per Mcf) +$ +5.08 +$ +4.35 +$ +2.59 +Operating Expenses (per BOE): +Production taxes and marketing +$ +5.65 +$ +4.89 +$ +3.54 +Lease operating +$ +8.75 +$ +9.04 +$ +8.56 +Depletion, depreciation and amortization +$ +22.95 +$ +22.96 +$ +24.43 +General and administrative +$ +5.48 +$ +4.85 +$ +4.42 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2014 from our primary operating areas: +Average Net Daily Production +Oil (Bbl/d) +Natural Gas (Mcf/d) +Oil Equivalent (BOE/d) (1) +Total Net Production (MBOE) (1) +Percentage of Total Net Production +South Texas: +Eagle Ford (2) +7,764 +16,423 +10,501 +3,833 +65.3 +% +NW Louisiana/E Texas: +Haynesville +— +19,740 +3,290 +1,201 +20.5 +% +Cotton Valley (3) +17 +2,903 +501 +183 +3.1 +% +Area Total +17 +22,643 +3,791 +1,384 +23.6 +% +Permian Basin: +SE New Mexico, West Texas +1,314 +2,859 +1,790 +653 +11.1 +% +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +9,095 +41,925 +16,082 +5,870 +100.0 +% +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(2) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +15 +Table of Contents +The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2013 from our primary operating areas: +Average Net Daily Production +Oil (Bbl/d) +Natural Gas (Mcf/d) +Oil Equivalent (BOE/d) (1) +Total Net Production (MBOE) (1) +Percentage of Total Net Production +South Texas: +Eagle Ford (2) +5,748 +14,865 +8,225 +3,002 +70.1 +% +NW Louisiana/E Texas: +Haynesville +— +16,984 +2,831 +1,033 +24.1 +% +Cotton Valley (3) +17 +3,498 +600 +219 +5.1 +% +Area Total +17 +20,482 +3,431 +1,252 +29.2 +% +Permian Basin: +SE New Mexico, West Texas +78 +36 +84 +31 +0.7 +% +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +5,843 +35,383 +11,740 +4,285 +100.0 +% +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(2) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 was an increase of 37% from our total oil equivalent production of approximately 4.3 million BOE for the year ended December 31, 2013 . This increased production was primarily due to our drilling operations in the Eagle Ford shale, as well as contributions from our initial wells in the Permian Basin. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, as compared to 11,740 BOE per day for the year ended December 31, 2013 . Our average daily oil production for the year ended December 31, 2014 was 9,095 Bbl of oil per day, an increase of 56% from 5,843 Bbl of oil per day for the year ended December 31, 2013 . Our average daily natural gas production for the year ended December 31, 2014 was 41.9 MMcf of natural gas per day, an increase of 18% from 35.4 MMcf of natural gas per day for the year ended December 31, 2013 . +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2014 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 93% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +South Texas: +Eagle Ford (1) +113 +95.2 +4 +4.0 +117 +99.2 +NW Louisiana/E Texas: +Haynesville +— +— +183 +16.8 +183 +16.8 +Cotton Valley (2) +2 +2.0 +95 +60.4 +97 +62.4 +Area Total +2 +2.0 +278 +77.2 +280 +79.2 +Permian Basin: +SE New Mexico, West Texas +26 +15.4 +5 +3.8 +31 +19.2 +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +— +Total +141 +112.6 +287 +85.0 +428 +197.6 +__________________ +16 +Table of Contents +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2014, 2013 and 2012 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Eagle Ford shale and the Permian Basin, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +At December 31, (1) +2014 +2013 +2012 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +24,184 +16,362 +10,485 +Natural Gas (Bcf) (3) +267.1 +212.2 +80.0 +Total (MBOE) (4) +68,693 +51,729 +23,819 +Estimated proved developed reserves: +Oil (MBbl) +14,053 +8,258 +4,764 +Natural Gas (Bcf) (3) +102.8 +53.5 +54.0 +Total (MBOE) (4) +31,185 +17,168 +13,771 +Percent developed +45.4 +% +33.2 +% +57.8 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +10,131 +8,104 +5,721 +Natural Gas (Bcf) (3) +164.3 +158.7 +26.0 +Total (MBOE) (4) +37,508 +34,561 +10,048 +PV-10 (5) (in millions) +$ +1,043.4 +$ +655.2 +$ +423.2 +Standardized Measure (6) (in millions) +$ +913.3 +$ +578.7 +$ +394.6 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.350 per MMBtu for natural gas, for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.670 per MMBtu for natural gas, and for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. +(3) +As a result of substantially lower natural gas prices in 2012, at June 30, 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves, most of which were attributable to non-operated properties. Primarily as a result of the continued improvement in natural gas prices during 2013, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2014 and 2013 . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2014, 2013 and 2012 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2014, 2013 and 2012 were, in millions, $130.1 , $76.5 and $28.6 , respectively. +17 +Table of Contents +(6) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +Our estimated total proved oil and natural gas reserves increase d 33% from 51.7 million BOE at December 31, 2013 to 68.7 million BOE at December 31, 2014 . Our proved oil reserves grew 48% from approximately 16.4 million Bbl at December 31, 2013 to approximately 24.2 million Bbl at December 31, 2014 . This increase is primarily attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas and our delineation and development operations in the Permian Basin. Our proved natural gas reserves increase d 26% from 212.2 Bcf at December 31, 2013 to 267.1 Bcf at December 31, 2014 . This increase in our proved natural gas reserves was attributable to our drilling and completion activities in 2014 and to Chesapeake’s drilling activities in the Haynesville shale on our Elm Grove properties that they operate. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf ( 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012. During 2013, primarily as a result of continued improvement in natural gas prices during the year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2014 and 2013 . The PV-10 of our total proved oil and natural gas reserves increase d 59% from $655.2 million at December 31, 2013 to $1.04 billion at December 31, 2014 . Our total proved reserves at December 31, 2014 were made up of approximately 35% oil and 65% natural gas, as compared to 32% oil and 68% natural gas at December 31, 2013 . +Our proved developed oil and natural gas reserves increase d 81% from 17.2 million BOE at December 31, 2013 to 31.2 million BOE at December 31, 2014 due primarily to our drilling programs in the Eagle Ford shale, our delineation and development operations in the Permian Basin and Chesapeake’s drilling activities in the Haynesville shale. Our proved developed oil reserves increase d 70% from 8.3 million Bbl at December 31, 2013 to 14.1 million Bbl at December 31, 2014 as a result of our drilling operations in the Eagle Ford shale and our delineation and development operations in the Permian Basin. Our proved developed natural gas reserves almost doubled from 53.5 Bcf at December 31, 2013 to 102.8 Bcf at December 31, 2014 due primarily to Chesapeake’s drilling activities in the Haynesville shale on our Elm Grove properties, which they operate. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2014 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2013 +17,168 +Extensions and discoveries +8,778 +Purchases of minerals-in-place +82 +Revisions of prior estimates +(196 +) +Production +(5,870 +) +Conversion of proved undeveloped to proved developed +11,223 +As of December 31, 2014 +31,185 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increased from 34.6 million BOE at December 31, 2013 to 37.5 million BOE at December 31, 2014 . Our proved undeveloped oil reserves increased from 8.1 million Bbl at December 31, 2013 to 10.1 million Bbl at December 31, 2014 , primarily as a result of our delineation and development operations in the Permian Basin. Our proved undeveloped natural gas reserves increased from 158.7 Bcf at December 31, 2013 to 164.3 Bcf at December 31, 2014 due primarily to our delineation and development operations in the Permian Basin and to wells drilled by our our co-working interest owners in the Haynesville shale. +At December 31, 2014 , we had no proved reserves in our estimates that remained undeveloped for five years or more following their booking. +18 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2014 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2013 +34,561 +Extensions and discoveries +15,143 +Purchases of minerals-in-place +— +Revisions of prior estimates +(973 +) +Conversion of proved undeveloped to proved developed +(11,223 +) +As of December 31, 2014 +37,508 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2012 , proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves Converted to Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2012 +283 +0.8 +415 +$ +8,096 +2013 +2,944 +8.3 +4,334 +115,699 +2014 +3,780 +44.7 +11,223 +201,950 +Total +7,007 +53.8 +15,972 +$ +325,745 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2014 : +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +PV-10 (2) +Standardized Measure (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +South Texas: +Eagle Ford (5) +16,106 +36.9 +22,257 +$ +603.8 +$ +528.5 +NW Louisiana/E Texas: +Haynesville +— +193.1 +32,183 +183.7 +160.8 +Cotton Valley (6) +26 +7.2 +1,223 +9.7 +8.5 +Area Total +26 +200.3 +33,406 +193.4 +169.3 +Permian Basin: +SE New Mexico, West Texas +8,052 +29.9 +13,030 +246.2 +215.5 +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +24,184 +267.1 +68,693 +$ +1,043.4 +$ +913.3 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2014 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2014 were approximately $ 130.1 million . +19 +Table of Contents +(3) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Vice President – Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 37 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. +20 +Table of Contents +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2014 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +South Texas: +Eagle Ford +23,835 +19,464 +16,036 +10,222 +39,871 +29,686 +NW Louisiana/E Texas: +Haynesville +17,605 +9,884 +3,690 +3,687 +21,295 +13,571 +Cotton Valley +18,776 +16,675 +3,586 +3,073 +22,362 +19,748 +Area Total (1) +22,895 +20,555 +4,356 +3,841 +27,251 +24,396 +Permian Basin: +SE New Mexico, West Texas +9,287 +7,109 +83,395 +58,967 +92,682 +66,076 +Other: +Wyoming, Utah, Idaho +1,600 +800 +74,074 +34,932 +75,674 +35,732 +Total +57,617 +47,928 +177,861 +107,962 +235,478 +155,890 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2014 that will expire prior to December 31, 2016 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. +Acres +Acres +Expiring 2015 +Expiring 2016 +Gross +Net +Gross +Net +South Texas: +Eagle Ford +1,607 +1,193 +2,631 +2,468 +NW Louisiana/E Texas: +Haynesville +— +— +839 +837 +Cotton Valley +— +— +80 +80 +Area Total (1) +— +— +839 +837 +Permian Basin: +SE New Mexico, West Texas (2) +5,875 +5,285 +32,918 +21,325 +Other: +Wyoming, Utah, Idaho +— +— +— +— +Total +7,482 +6,478 +36,388 +24,630 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +(2) +Approximately 60% of the acreage expiring in 2016 is associated with our Twin Lakes prospect in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2014 , our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. +21 +Table of Contents +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2014, 2013 and 2012 : +Year Ended December 31, +2014 +2013 +2012 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +89 +39.9 +32 +20.7 +36 +17.1 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +12 +10.6 +14 +8.7 +22 +10.4 +Dry (1) +— +— +1 +0.4 +— +— +Total Wells +Productive +101 +50.5 +46 +29.4 +58 +27.5 +Dry (1) +— +— +1 +0.4 +— +— +__________________ +(1) We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013. +Marketing +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the year ended December 31, 2014 , we had three significant purchasers that accounted for approximately 68% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2013 and 2012 , we had five and three significant purchasers that accounted for approximately 87% and 74% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +22 +Table of Contents +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, we had an immaterial natural gas deficiency and the counterparty to this agreement waived the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations. +Competition +The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas +23 +Table of Contents +Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. +Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue. +In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. +The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates +24 +Table of Contents +are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). +Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. +Environmental Regulation +The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the +25 +Table of Contents +OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. +26 +Table of Contents +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In December 2014, the EPA issued finalized additional amendments to these rules that, among other things, distinguished between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks permanently removed from service are not affected by any requirements. These rules have required changes to our operations, including the installation of new equipment to control emissions. We continue to evaluate the effect these rules have on our business and operations, which effects we do not expect to be material. Further, in 2012, seven states sued the EPA to compel the agency to make a determination as to whether setting standards of performance limiting methane emissions from oil and natural gas sources is appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and natural gas sources. In April 2014, the EPA released a set of five white papers analyzing methane emissions from the industry. In January 2015, EPA announced plans to issue a rule in summer 2015 governing methane emissions from the oil and natural gas industry. The Bureau of Land Management (BLM) is also expected to address methane emissions from the oil and natural gas industry on federal lands. These rules could increase our operating costs and have a material adverse effect on our business and operations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future international agreements, federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the +27 +Table of Contents +disposal of produced water. As of December 31, 2014 , we owned and operated five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows. +In addition, in some states and localities, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few state and local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. For example, in December 2014 New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. Voters in the city of Denton, Texas also recently approved a moratorium on hydraulic fracturing. These actions are the subject of legal challenges. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. +The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA recently issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, the EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released in December 2012, with draft final results expected in early 2015. Further, the BLM has proposed rules to regulate hydraulic fracturing on federal lands. The EPA has also announced an Advance Notice of Proposed Rulemaking under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, +have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and +28 +Table of Contents +similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K. Such information is incorporated herein by reference. +Employees +At December 31, 2014 , we had 99 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance +29 +Table of Contents +materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +Item 1A. Risk Factors. +Risks Related to the Oil and Natural Gas Industry and Our Business +Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. +The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2014, the price of oil decreased 50% from a high of $107.26 per Bbl in mid-June to a low of $53.27 per Bbl in late December, and the price of natural gas decreased 53% from a high of $6.15 per MMBtu in mid-February to a low of $2.89 per MMBtu in late December. Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows. Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines may cause us to recognize a full-cost ceiling impairment, which reduces the book value of our net tangible assets, retained earnings and shareholders’ equity but does not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.” +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• +the domestic and foreign supply of oil and natural gas; +• +the domestic and foreign demand for oil and natural gas; +• +the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; +• +the prices and availability of competitors’ supplies of oil and natural gas; +• +the price and quantity of foreign imports; +• +the impact of U.S. dollar exchange rates on oil and natural gas prices; +• +domestic and foreign governmental regulations and taxes; +• +speculative trading of oil and natural gas futures contracts; +• +the availability, proximity and capacity of gathering, processing and transportation systems for natural gas; +• +the availability of refining capacity; +• +the prices and availability of alternative fuel sources; +• +weather conditions and natural disasters; +• +political conditions in or affecting oil and natural gas producing regions or countries, including the Middle East, South America and Russia; +• +the continued threat of terrorism and the impact of military action and civil unrest; +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; +• +the level of global oil and natural gas inventories and exploration and production activity; +• +the impact of energy conservation efforts; +• +technological advances affecting energy consumption; and +30 +Table of Contents +• +overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. +Approximately 57% of our total production during the year ended December 31, 2014 and 35% of our proved reserves at December 31, 2014 were attributable to oil. Approximately 43% of our total production during the year ended December 31, 2014 and 65% of our proved reserves at December 31, 2014 were attributable to natural gas. +During 2015, we plan to direct approximately 70% of our capital expenditures to the Wolfcamp and Bone Spring plays in the Permian Basin and 26% of our capital expenditures to the Eagle Ford shale, each of which is prospective for oil and liquids production. These opportunities are sensitive to changes in oil prices. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities (as we have done with our operated natural gas properties in recent years), each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. +Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of oil and natural gas reserves. Our cash, operating cash flows and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +We may sell additional equity securities or issue debt securities to raise capital. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our estimated proved oil and natural gas reserves; +• +the amount of oil and natural gas we produce from existing wells; +• +the prices at which we sell our production; +• +the costs of developing and producing our oil and natural gas reserves; +• +our ability to acquire, locate and produce new reserves; +• +the ability and willingness of banks to lend to us; and +• +our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, significant decreases in the prices of oil and natural gas, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +31 +Table of Contents +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain exploration opportunities. Alternatively, to fund acquisitions, increase our rate of growth, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. +Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• +general economic and industry conditions, including the prices received for oil and natural gas; +• +shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• +potential drainage by operators on adjacent properties; +• +loss of or damage to oilfield development and service tools; +• +accidents, equipment failures or mechanical problems; +• +problems with title to the underlying properties; +• +increases in severance taxes; +• +adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• +domestic and foreign governmental regulations; and +• +proximity to and capacity of gathering, processing and transportation facilities. +If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +We May Incur Additional Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. +At February 27, 2015, following the closing of the HEYCO Merger, we had available borrowings of approximately $54.4 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by substantially all of our interests in our oil and natural gas properties, other than those properties acquired in the HEYCO Merger (which properties separately secure the approximately $12.0 million in indebtedness we assumed in the HEYCO Merger), and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay +32 +Table of Contents +dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. +In the future, we may incur significant amounts of additional indebtedness, including under our Credit Agreement, in order to fund acquisitions, develop our properties or invest in certain exploration opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• +requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• +increasing our vulnerability to general adverse economic and industry conditions; +• +placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• +restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• +increasing the risk that we may default on our debt obligations. +Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including: +• +natural disasters; +• +adverse weather conditions; +• +loss of drilling fluid circulation; +• +blowouts where oil or natural gas flows uncontrolled at a wellhead; +• +cratering or collapse of the formation; +• +pipe or cement leaks, failures or casing collapses; +• +fires or explosions; +• +releases of hazardous substances or other waste materials that cause environmental damage; +• +pressures or irregularities in formations; and +• +equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of +33 +Table of Contents +insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Eagle Ford shale in South Texas, the Permian Basin in Southeast New Mexico and West Texas and the Haynesville shale in Northwest Louisiana and East Texas. For the year ended December 31, 2014 , approximately 65% of our total oil and natural gas production, including approximately 85% of our average daily oil production, was attributable to our properties in South Texas and approximately 11% of our total oil and natural gas production, including approximately 14% of our average daily oil production, was attributable to our properties in the Permian Basin. At December 31, 2014 , approximately 58% of the PV-10 of our total proved oil and natural gas reserves and approximately 67% of our total proved oil reserves were attributable to our properties in South Texas, primarily in the Eagle Ford shale, and approximately 24% of the PV-10 of our total proved oil and natural gas reserves and approximately 33% of our total proved oil reserves were attributable to our properties in the Permian Basin. We expect that most of our operations in 2015 will be primarily in the Permian Basin. We expect to direct approximately 70% of our 2015 capital expenditures to further delineating and developing our acreage position in the Permian Basin in Southeast New Mexico and West Texas and 26% of our 2015 capital expenditures to further developing our acreage position in the Eagle Ford shale in South Texas. +The industry focus on the Eagle Ford shale and the Permian Basin may adversely impact our ability to transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil and condensate trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Even though we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, due to the concentration of our operations we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, during the fourth quarters of 2013 and 2014, the Permian Basin experienced severe winter weather that impacted many operators. In particular, the weather conditions and freezing temperatures resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In the third quarter of 2014, certain areas of the Permian Basin experienced severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we increase our operations and production in the Permian Basin, we may increasingly face these and other challenges posed by severe weather. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Permian Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic +34 +Table of Contents +fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs could result which could adversely affect our business, financial condition, results of operations and cash flows. +If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Permian Basin and the Eagle Ford shale, areas in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in these areas and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the judgment of the persons preparing the estimate; and +• +the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves. +35 +Table of Contents +The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report on Form 10-K is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +actual costs and timing of development and production expenditures; +• +the amount and timing of actual production; and +• +changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 61% of Our Total Proved Reserves at December 31, 2014 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. +At December 31, 2014 , approximately 55% of our total proved reserves were undeveloped and approximately 6% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including assessment of risks, costs, drilling results, oil and natural gas prices, the availability of equipment and capital, approval by regulators, lease terms and seasonal conditions. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. +At December 31, 2014 , we had leasehold interests in approximately 31,100 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2016 . Unless we establish production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third party leases may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +36 +Table of Contents +The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic and geological data can be expensive to license or obtain and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. +Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected. +Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. +Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we will endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business, as well as certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue. +The unavailability of satisfactory oil, natural gas and natural gas liquids gathering, processing and transportation arrangements may hinder our access to oil, natural gas and natural gas liquids markets or delay production from our wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for, and supply of, oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and +37 +Table of Contents +terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Permian Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas occasionally, which would decrease the volumes sold from our wells. +The disruption of third party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and natural gas liquids. The third parties control when or if such facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, no assurance can be given that this agreement will alleviate these issues completely, and we may be required to pay deficiency payments under this agreement if we do not meet the thermal quantity transportation and processing commitments under this agreement. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp and Bone Spring plays in the Permian Basin in 2015 . If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. +Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. +We derive most of our revenues from the sale of our oil, natural gas and natural gas liquids to unaffiliated third party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows. +Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. +The operations of the third parties on whom we rely for gathering, processing and transportation services, and, to a lesser extent, affiliate companies providing limited amounts of such services, are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” +We Have Limited Control over Activities on Properties We Do Not Operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to Chesapeake in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our +38 +Table of Contents +limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• +timing and amount of capital expenditures; +• +the operator’s expertise and financial resources; +• +the rate of production of reserves, if any; +• +approval of other participants in drilling wells; and +• +selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. +In addition, we may be unable to successfully integrate any potential acquisitions into our existing operations. The inability to manage the integration of acquisitions, including the HEYCO Merger, effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, including with respect to the HEYCO Merger, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our Credit Agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We May be Unsuccessful in Combining HEYCO’s Business with Our Existing Business. +The success of the HEYCO Merger will depend, in part, on our ability to realize the anticipated benefits and synergies from combining our business and existing asset base with the business of HEYCO and the assets obtained in the HEYCO Merger. To realize these anticipated benefits, the businesses must be successfully integrated. If we are not able to achieve these objectives, or we are not able to achieve these objectives on a timely basis, the anticipated benefits of the HEYCO Merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the HEYCO Merger. These integration difficulties could have a material adverse effect on our business, financial condition and results of operations. +We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. +Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems +39 +Table of Contents +associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. +If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired or other title deficiencies, our interest would be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. +It is not our practice in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease in all acquisitions. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows. +We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have: +• +downward adjustments to our estimated proved reserves; +• +increases in our estimates of development costs; or +• +deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. Although uncertain future prices impact the ability to predict future full cost ceiling impairments, we do anticipate recognizing full-cost ceiling impairments in 2015, beginning as early as the first quarter of 2015. This conclusion is based on the historic prices for the last nine months of 2014 and the first two months of 2015 as well as the short-term pricing outlook. Although we can predict with relative certainty that we will recognize full-cost ceiling impairments in 2015, we are not able to reasonably estimate the amounts. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and could lower the value of our common stock. +Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges +40 +Table of Contents +is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. We currently have no hedges in place for oil, natural gas or natural gas liquids beyond 2015. +An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials. +We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for: +• +personal injuries; +• +property damage; +• +containment and clean-up of oil and other spills; +• +management and disposal of hazardous materials; +• +remediation, clean-up costs and natural resource damages; and +• +other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. +41 +Table of Contents +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered species could prohibit drilling in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production activities, each of which could have an adverse impact on our ability to develop and produce our reserves. +We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. +In past sessions, Congress has considered, but did not pass, legislation to amend the Safe Drinking Water Act, or SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. The EPA recently issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and natural gas liquids from formations such as the Eagle Ford shale, the Wolfcamp and Bone Spring plays and the Haynesville shale, where we focus our operations. The EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. A progress report was released in December 2012, with draft final results expected in early 2015. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action towards federal legislation and regulation of hydraulic fracturing or similar production operations. Also at the federal level, the BLM has proposed rules to regulate hydraulic fracturing on federal lands. Additionally, the EPA has issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. +In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans/moratoria on drilling and effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014 New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. Voters in the city of Denton, Texas also recently approved a moratorium on hydraulic fracturing. These actions are the subject of legal challenges. Texas and Wyoming have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. These restrictions and regulations could increase our costs of compliance and doing business. +42 +Table of Contents +The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. +The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports filed in 2012. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. +On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In December 2014, the EPA issued finalized additional amendments to these rules that, among other things, distinguished between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks permanently removed from service are not affected by any requirements. These rules have required changes to our operations, including the installation of new equipment to control emissions. We continue to evaluate the effect these rules have on our business and operations, which are not anticipated to be materially impacted. Further, in 2012, seven states sued the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and natural gas sources is appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and natural gas sources. In April 2014, the EPA released a set of five white papers analyzing methane emissions from the industry. In January 2015, EPA announced plans to issue a rule in summer 2015 governing methane emissions from the oil and natural gas industry. The Bureau of Land Management (BLM) is also expected to address methane emissions from the oil and natural gas industry on federal lands. These rules could increase our operating costs and have a material adverse effect on our business and operations. +43 +Table of Contents +The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the oil, natural gas and natural gas liquids that we produce. +A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. A change in the jurisdictional characterization by FERC, the courts or Congress or a change in policy by FERC or Congress may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. The nature of our gathering facilities is such that we have not yet been regulated by FERC as a natural gas company subject to the provisions of the NGA. It is possible, however, that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. +On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished. +In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +44 +Table of Contents +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including any increase in oil exploration, development and production, and any increase in the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. Certain of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or Financial Loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion and production operations and data, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. +While we have not experienced any material losses due to cyber attacks, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to our proprietary information which could lead to data corruption, communication interruption, exposure of confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Risks Relating to Our Common Stock and Preferred Stock +The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2014 , our stock price fluctuated between a high of $29.94 and a low of $14.08. In the future, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our +45 +Table of Contents +common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• +our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• +quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• +changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• +speculation in the press or investment community; +• +announcement or consummation of acquisitions or dispositions by us; +• +public reaction to our press releases, announcements and filings with the SEC; +• +sales of our common stock by us or shareholders, or the perception that such sales may occur; +• +general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices; +• +the realization of any of the risk factors presented in this Annual Report on Form 10-K; +• +the recruitment or departure of key personnel; +• +commencement of or involvement in litigation; +• +the prices of oil, natural gas and natural gas liquids; +• +the success of our exploration and development operations, and the marketing of any oil, natural gas and natural gas liquids we produce; +• +changes in market valuations of companies similar to ours; and +• +domestic and international economic, legal and regulatory factors unrelated to our performance. +If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and occupies a significant amount of time of our Board of Directors and management and has significantly increased our costs and expenses. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal controls over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Further, our remediation efforts may not enable us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. +We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Any future cash dividends paid to holders of our common stock will also be owed to the holders of our Series A Preferred Stock on an as-converted basis. In addition, certain covenants in our Credit Agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to +46 +Table of Contents +generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. +Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of preferred stock convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or securities convertible into common stock in public or private offerings or in connection with acquisitions, such as our Series A Preferred Stock issued in the HEYCO Merger. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• +authorization for our Board of Directors to issue preferred stock without shareholder approval, such as our Series A Preferred Stock issued in the HEYCO Merger; +• +a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• +the prohibition of cumulative voting in the election of directors; and +• +a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +Our Directors and Executive Officers Own a Significant Percentage of Our Equity, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. +As of February 27, 2015, our directors and executive officers beneficially owned approximately 9% of our outstanding common stock and Series A Preferred Stock on an as-converted basis. Following the addition of George M. Yates to our board of directors, which we expect to occur no later than April 15, 2015, our directors and executive officers are expected to beneficially own approximately 15% of our outstanding common stock and Series A Preferred Stock on an as-converted basis. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. For example, in connection with the HEYCO Merger, we issued 150,000 shares of our Series A Preferred Stock, which will convert into shares of our common +47 +Table of Contents +stock on a basis of 10 shares of common stock for each share of Series A Preferred Stock upon our shareholders’ approval of the Charter Amendment. The holders of Series A Preferred Stock will vote, on an as-converted basis, together with the holders of common stock as a single class, except with respect to matters that would adversely affect the holders of Series A Preferred Stock as compared to the holders of common stock, in which case the holders of Series A Preferred Stock will vote as a separate class. +Issuances of preferred stock, such as the issuance of our Series A Preferred Stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the company, even if that change of control might benefit our shareholders. +We May be Required to Pay Dividends on Shares of Our Series A Preferred Stock. +If our outstanding shares of Series A Preferred Stock are outstanding as of August 27, 2015, the holders of Series A Preferred Stock will be entitled to receive dividends on the Series A Preferred Stock in cash at a quarterly rate of $1.80 per share. The payment of such dividends may require a significant portion of our cash flows, which could materially adversely affect our financial condition and results of operations. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K. Such information is incorporated herein by reference. +Item 4. Mine Safety Disclosures. +Not applicable. +48 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 27, 2015 , following the closing of the HEYCO Merger, we had 76,728,605 shares of common stock outstanding held by approximately 350 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated: +2014 +2013 +High +Low +High +Low +First Quarter +$ +25.84 +$ +17.95 +$ +9.00 +$ +7.58 +Second Quarter +$ +29.36 +$ +23.28 +$ +12.48 +$ +8.25 +Third Quarter +$ +29.94 +$ +23.70 +$ +17.89 +$ +11.49 +Fourth Quarter +$ +26.09 +$ +14.08 +$ +24.10 +$ +15.62 +On February 27, 2015 , the last reported sales price of our common stock on the NYSE was $21.66 per share. +Dividend Policy +We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our Credit Agreement may limit our ability to pay dividends on our common stock. During the years ended December 31, 2014 and 2013 , we did not pay dividends to holders of our common stock. +As part of the consideration for the HEYCO Merger, we issued 150,000 shares of Series A Preferred Stock. Each share of Series A Preferred Stock will automatically convert into ten shares of our common stock, subject to customary anti-dilution adjustments, upon the vote and approval by our shareholders of the Charter Amendment. On February 25, 2015, we filed a definitive proxy statement with the Securities and Exchange Commission and began mailing to our shareholders such proxy materials related to a special meeting of shareholders to be held on April 2, 2015 at 9:30 a.m., Central Time, for the purpose of approving the Charter Amendment. All shareholders of record as of the close of business on February 18, 2015 will be entitled to vote at the special meeting. +If shares of our Series A Preferred Stock are outstanding as of August 27, 2015, the holders of such shares will be entitled to receive dividends on the Series A Preferred Stock in cash at a quarterly rate of $1.80 per share of Series A Preferred Stock. The payment of such dividends may require a significant portion of our cash flows, which could materially adversely affect our financial condition and results of operations. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2014 . +49 +Table of Contents +Equity Compensation Plan Information +Plan Category +Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights +Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights +Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1) (2) +1,968,182 +$ +12.47 +1,347,463 +Equity compensation plans not approved by security holders +— +— +— +Total +1,968,182 +$ +12.47 +1,347,463 +__________________ +(1) +Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. +(2) +Our 2012 Long-Term Incentive Plan was approved by our Board of Directors in December 2011 and took effect on January 1, 2012. The 2012 Long-Term Incentive Plan was also approved by our shareholders at the Annual Meeting of Shareholders on June 7, 2012. For a description of our 2012 Long-Term Incentive Plan, see “ Note 8 – Stock-Based Compensation ” to the consolidated financial statements in this Annual Report on Form 10-K. +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from February 2, 2012, the date our common stock began trading on the NYSE, through December 31, 2014 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act , whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +50 +Table of Contents +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +51 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2014, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs +Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2014 to October 31, 2014 +— +$ +— +— +— +November 1, 2014 to November 30, 2014 +787 +23.35 +— +— +December 1, 2014 to December 31, 2014 +779 +20.23 +— +— +Total +1,566 +$ +21.80 +— +— +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. +52 +Table of Contents +Item 6. Selected Financial Data. +You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K. The financial information included in this Annual Report on Form 10-K may not be indicative of our future results of operations, financial condition or cash flows. +The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2014 and selected consolidated balance sheet data at December 31, 2014 , 2013 , 2012 , 2011 and 2010 and should be read in conjunction with the consolidated financial statements for the years ended December 31, 2014, 2013 and 2012 included herewith. +Year Ended December 31, +2014 +2013 +2012 +2011 +2010 +(In thousands, except per share data) +Statement of operations data: +Revenues +Oil and natural gas revenues +$ +367,712 +$ +269,030 +$ +155,998 +$ +67,000 +$ +34,042 +Realized gain (loss) on derivatives +5,022 +(909 +) +13,960 +7,106 +5,299 +Unrealized gain (loss) on derivatives +58,302 +(7,232 +) +(4,802 +) +5,138 +3,139 +Total revenues +431,036 +260,889 +165,156 +79,244 +42,480 +Expenses +Production taxes and marketing +33,172 +20,973 +11,672 +6,278 +1,982 +Lease operating +51,353 +38,720 +28,184 +7,244 +5,284 +Depletion, depreciation and amortization +134,737 +98,395 +80,454 +31,754 +15,596 +Accretion of asset retirement obligations +504 +348 +256 +209 +155 +Full-cost ceiling impairment +— +21,229 +63,475 +35,673 +— +General and administrative +32,152 +20,779 +14,543 +13,394 +9,702 +Total expenses +251,918 +200,444 +198,584 +94,552 +32,719 +Operating income (loss) +179,118 +60,445 +(33,428 +) +(15,308 +) +9,761 +Other income (expense): +Net loss on asset sales and inventory impairment +— +(192 +) +(485 +) +(154 +) +(224 +) +Interest expense +(5,334 +) +(5,687 +) +(1,002 +) +(683 +) +(3 +) +Interest and other income +1,345 +225 +224 +315 +364 +Total other (expense) income +(3,989 +) +(5,654 +) +(1,263 +) +(522 +) +137 +Net income (loss) +110,754 +45,094 +(33,261 +) +(10,309 +) +6,377 +Net loss attributable to non-controlling interest in subsidiary +17 +— +— +— +— +Net income (loss) attributable to +Matador Resources Company shareholders +$ +110,771 +$ +45,094 +$ +(33,261 +) +$ +(10,309 +) +$ +6,377 +Earnings (loss) per common share +Basic +Class A +$ +1.58 +$ +0.77 +$ +(0.62 +) +$ +(0.25 +) +$ +0.15 +Class B +$ +— +$ +— +$ +(0.35 +) +$ +0.02 +$ +0.42 +Diluted +Class A +$ +1.56 +$ +0.77 +$ +(0.62 +) +$ +(0.25 +) +$ +0.15 +Class B +$ +— +$ +— +$ +(0.35 +) +$ +0.02 +$ +0.42 +Class B dividend declared, per share +$ +— +$ +— +$ +0.27 +$ +0.27 +$ +0.27 +53 +Table of Contents +At December 31, +2014 +2013 +2012 +2011 +2010 +(In thousands) +Balance sheet data: +Cash and cash equivalents +$ +8,407 +$ +6,287 +$ +2,095 +$ +10,284 +$ +21,060 +Restricted cash +609 +— +— +— +— +Certificates of deposit +— +— +230 +1,335 +2,349 +Net property and equipment +1,322,072 +845,877 +591,090 +399,865 +303,880 +Total assets +1,436,291 +890,330 +632,029 +439,469 +346,382 +Current liabilities +161,787 +100,327 +96,492 +74,576 +30,097 +Long-term liabilities +407,963 +221,079 +156,433 +93,378 +34,408 +Total Matador Resources Company shareholders' equity +$ +866,408 +$ +568,924 +$ +379,104 +$ +271,515 +$ +281,877 +Year Ended December 31, +2014 +2013 +2012 +2011 +2010 +(In thousands) +Other financial data: +Net cash provided by operating activities +$ +251,481 +$ +179,470 +$ +124,228 +$ +61,868 +$ +27,273 +Net cash used in investing activities +(570,531 +) +(366,939 +) +(306,916 +) +(160,088 +) +(147,334 +) +Oil and natural gas properties capital expenditures +(560,849 +) +(363,192 +) +(300,689 +) +(156,431 +) +(159,050 +) +Expenditures for other property and equipment +(9,152 +) +(3,977 +) +(7,332 +) +(4,671 +) +(1,610 +) +Net cash provided by financing activities +321,170 +191,661 +174,499 +87,444 +36,891 +Adjusted EBITDA (1) +$ +262,943 +$ +191,771 +$ +115,923 +$ +49,911 +$ +23,635 +__________________ +(1) +Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “ – Non-GAAP Financial Measures” below. +Non-GAAP Financial Measures +We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +54 +Table of Contents +Year Ended December 31, +2014 +2013 +2012 +2011 +2010 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net income (loss) attributable to Matador Resources Company shareholders +$ +110,771 +$ +45,094 +$ +(33,261 +) +$ +(10,309 +) +$ +6,377 +Interest expense +5,334 +5,687 +1,002 +683 +3 +Total income tax provision (benefit) +64,375 +9,697 +(1,430 +) +(5,521 +) +3,521 +Depletion, depreciation and amortization +134,737 +98,395 +80,454 +31,754 +15,596 +Accretion of asset retirement obligations +504 +348 +256 +209 +155 +Full-cost ceiling impairment +— +21,229 +63,475 +35,673 +— +Unrealized (gain) loss on derivatives +(58,302 +) +7,232 +4,802 +(5,138 +) +(3,139 +) +Stock-based compensation expense +5,524 +3,897 +140 +2,406 +898 +Net loss on asset sales and inventory impairment +— +192 +485 +154 +224 +Adjusted EBITDA +$ +262,943 +$ +191,771 +$ +115,923 +$ +49,911 +$ +23,635 +Year Ended December 31, +2014 +2013 +2012 +2011 +2010 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities +$ +251,481 +$ +179,470 +$ +124,228 +$ +61,868 +$ +27,273 +Net change in operating assets and liabilities +5,978 +6,210 +(9,307 +) +(12,594 +) +(2,230 +) +Interest expense +5,334 +5,687 +1,002 +683 +3 +Current income tax provision (benefit) +133 +404 +— +(46 +) +(1,411 +) +Net loss attributable to non-controlling interest in subsidiary +17 +— +— +— +— +Adjusted EBITDA +$ +262,943 +$ +191,771 +$ +115,923 +$ +49,911 +$ +23,635 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +Overview +We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share (the “Initial Public Offering”). We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +55 +Table of Contents +On September 10, 2013 , we completed an underwritten public offering of 9,775,000 shares of our common stock, including 1,275,000 shares issued pursuant to the underwriters’ exercise of their option to purchase additional shares. After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million , we received net proceeds of approximately $141.7 million . We used the net proceeds from this offering primarily to fund a portion of our capital expenditures, including for the addition of a third rig to our drilling program. We also used the net proceeds from this offering to fund the acquisition of additional acreage in the Eagle Ford shale, the Permian Basin and the Haynesville shale and for other general working capital needs. Pending such uses, we used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under our Credit Agreement in September 2013, which amounts were subsequently reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. +On May 29, 2014, we completed a public offering of 7,500,000 shares of our common stock. After deducting direct offering costs totaling approximately $0.6 million , we received net proceeds of approximately $181.3 million . We used a portion of the net proceeds to repay $180.0 million in outstanding borrowings under our Credit Agreement, which amounts were subsequently reborrowed in accordance with the terms of that facility. The remaining $1.3 million of the offering net proceeds was used to fund working capital requirements. +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Prices for oil, natural gas and natural gas liquids will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices would not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. During 2014, we experienced sharp declines in oil and natural gas prices. For the year ended December 31, 2014 , West Texas Intermediate oil prices declined from a high of approximately $107.26 per Bbl in mid-June to a low of $53.27 per Bbl in late December. Natural gas prices declined from a high of approximately $6.15 per MMBtu in mid-February to a low of approximately $2.89 per MMBtu in late December. As a result of this decline in commodity prices, we expect to reduce our drilling activities and capital expenditures by about 43% to $350.0 million (excluding capital expenditures associated with the HEYCO Merger) in 2015, as compared to the year ended December 31, 2014 . +During the year ended December 31, 2014 , we completed and began producing oil and natural gas from 36 gross (34.5 net) operated and eight gross (2.2 net) non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from ten gross (9.5 net) operated and one gross (0.1 net) non-operated wells in the Permian Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2014, although we did participate in the drilling and completion of 46 gross (4.2 net) non-operated Haynesville shale wells, the most impactful of which were 14 gross (3.3 net) Haynesville wells completed and placed on production by Chesapeake on our Elm Grove properties in southern Caddo Parish, Louisiana. +In 2014 , approximately 56% of our total capital expenditures of $610.4 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we continued to increase our oil production and oil reserves. We also continued the evaluation and delineation of our acreage position in the Permian Basin during 2014 . We increased our leasehold position significantly in the Permian Basin in Southeast New Mexico and West Texas during 2014 . At December 31, 2014 , we held approximately 92,700 gross (66,100 net) acres in the Permian Basin, as compared to approximately 70,800 gross (44,800 net) acres at December 31, 2013 , and with the closing of the HEYCO Merger on February 27, 2015, our Permian Basin acreage position increased to 154,200 gross (85,400 net) acres. Approximately 37% of our 2014 capital expenditures were directed to our exploration and delineation program testing portions of our leasehold position in the Permian Basin and to the acquisition of additional leasehold interests prospective for the Wolfcamp, Bone Spring and other oil and liquids-rich plays in the Permian Basin. In the first half of 2014, Chesapeake began the process of drilling up to an anticipated 45 gross (8.7 net) Haynesville shale wells on our Elm Grove acreage in southern Caddo Parrish, Louisiana, which we expect to continue through early 2017. We retain the right to participate for up to a 25% working interest in all wells drilled on this property with our working interest proportionately reduced to our leasehold position in any individual drilling unit. After notifying us of its intent to conduct this drilling program, Chesapeake began actively drilling these properties during the second quarter of 2014, and had up to five rigs operating on these properties at any one time during 2014. Approximately 7% of our total capital expenditures of $610.4 million were associated with non-operated Haynesville shale wells in 2014, including those wells drilled by Chesapeake. +Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, an increase of 37% as compared to 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, for the year ended December 31, 2013 . Our average daily oil production in 2014 of 9,095 Bbl of oil per day was an increase of 56% , as compared to an average daily oil production +56 +Table of Contents +of 5,843 Bbl of oil per day in 2013. This increase in oil production is primarily attributable to our ongoing development operations in the Eagle Ford shale as well as better-than-expected initial production contributions from wells drilled in the Permian Basin during 2014. Our average daily natural gas production of 41.9 Bcf per day for the year ended December 31, 2014 was an increase of 18% from 35.4 Bcf per day for the year ended December 31, 2013 . This increase in natural gas production is primarily attributable to initial production contributions from wells drilled in the Permian Basin and to the increased natural gas production resulting from new, non-operated Haynesville shale wells completed and placed on production by Chesapeake on our Elm Grove properties in Northwest Louisiana during the second half of 2014. Our oil production, natural gas production and average daily oil equivalent production during 2014 were the best in Matador’s history. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2014 , as compared to 50% for the year ended December 31, 2013 and only 37% for the year ended December 31, 2012 . +Our oil and natural gas revenues and Adjusted EBITDA for the year ended December 31, 2014 were also the highest achieved for any year in our history. For the year ended December 31, 2014 , our oil and natural gas revenues were $367.7 million , an increase of 37% from oil and natural gas revenues of $269.0 million for the year ended December 31, 2013 . Our oil revenues and natural gas revenues increased 36% and 38% to approximately $290.0 million and $77.7 million , respectively, for the year ended December 31, 2014 , as compared to $212.8 million and $56.2 million , respectively, for the year ended December 31, 2013 . Adjusted EBITDA for the year ended December 31, 2014 was $262.9 million , an increase of 37% from an Adjusted EBITDA of $191.8 million reported for the year ended December 31, 2013 . Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +At December 31, 2014 , our estimated total proved oil and natural gas reserves were 68.7 million BOE, including 24.2 million Bbl of oil and 267.1 Bcf of natural gas, with a PV-10 of $1.04 billion and a Standardized Measure of $913.3 million . At December 31, 2013 , our estimated proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, with a PV-10 of $655.2 million and a Standardized Measure of $578.7 million . Our estimated proved oil reserves of 24.2 million Bbl at December 31, 2014 increased 48% , as compared to 16.4 million Bbl at December 31, 2013 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” +Our estimated capital expenditure budget for 2015 is $350 million (excluding capital expenditures associated with the HEYCO Merger), and 96% is expected to be directed towards oil and liquids-rich opportunities. We expect to reduce our operated drilling program from five rigs, three in the Permian Basin and two in the Eagle Ford in January 2015, to two rigs early in the second quarter. We then plan to operate two rigs in the Permian Basin, one rig in Loving County, Texas and the other rig in Lea and Eddy Counties, New Mexico, for the remainder of 2015. As approximately 96% of our Eagle Ford acreage is either held by production or not burdened by leasehold expiration until 2016 or later, we plan to temporarily suspend our drilling activities in South Texas in 2015 until commodity prices improve sufficiently. +Development of our Permian Basin assets will be the primary driver of our growth in 2015 and approximately $245 million , or 70% , of our 2015 estimated capital expenditures will be allocated to further delineation and development of our growing leasehold position in the Permian Basin. Our 2015 Permian Basin drilling program will focus on the development of the Wolf prospect area, the further delineation of the Ranger and Rustler Breaks prospect areas and the integration of the HEYCO acreage. We still plan to direct approximately $90 million , or 26% , of our estimated 2015 capital expenditures to drilling and completion operations in the Eagle Ford shale in South Texas. Although we do not plan to drill any operated Haynesville shale natural gas wells during 2015 , approximately $15 million , or 4% , of our 2015 estimated capital expenditures will be allocated to participation in non-operated Haynesville shale wells in Northwest Louisiana. We believe that we should be able to fund our 2015 drilling program through a combination of operating cash flows, borrowings under our Credit Agreement (assuming availability under our borrowing base) or additional credit arrangements, potential joint ventures, the sale of assets or acreage and the potential issuance of equity and debt securities. While we have budgeted approximately $350.0 million of capital expenditures (excluding capital expenditures associated with the HEYCO Merger) for 2015 , the aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, wells drilled on properties we do not operate, our drilling results, other opportunities that may become available to us and our ability to obtain capital. +57 +Table of Contents +Revenues +Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices. +The following table summarizes our revenues and production data for the periods indicated: +Year Ended December 31, +2014 +2013 +2012 +Operating Data: +Revenues (in thousands): (1) +Oil +$ +290,026 +$ +212,833 +$ +123,654 +Natural gas +77,686 +56,197 +32,344 +Total oil and natural gas revenues +367,712 +269,030 +155,998 +Realized gain (loss) on derivatives +5,022 +(909 +) +13,960 +Unrealized gain (loss) on derivatives +58,302 +(7,232 +) +(4,802 +) +Total revenues +$ +431,036 +$ +260,889 +$ +165,156 +Net Production Volumes: (1) +Oil (MBbl) +3,320 +2,133 +1,214 +Natural gas (Bcf) +15.3 +12.9 +12.5 +Total oil equivalent (MBOE) (2) +5,870 +4,285 +3,294 +Average daily production (BOE/d) (2) +16,082 +11,740 +9,000 +Average Sales Prices: +Oil, with realized derivatives (per Bbl) +$ +88.94 +$ +98.67 +$ +103.55 +Oil, without realized derivatives (per Bbl) +$ +87.37 +$ +99.79 +$ +101.86 +Natural gas, with realized derivatives (per Mcf) +$ +5.06 +$ +4.47 +$ +3.55 +Natural gas, without realized derivatives (per Mcf) +$ +5.08 +$ +4.35 +$ +2.59 +________________ +(1) +We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues. +(2) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2014 as Compared to Year Ended December 31, 2013 +Oil and natural gas revenues . Our oil and natural gas revenues increased $98.7 million to $367.7 million , or an increase of 37% for the year ended December 31, 2014 , as compared to $269.0 million for the year ended December 31, 2013 . This increase in oil and natural gas revenues corresponds with an increase of 37% in our oil and natural gas production to 5.9 million BOE for the year ended December 31, 2014 from 4.3 million BOE for the year ended December 31, 2013 . Our oil revenues increase d $77.2 million , an increase of 36% , to $290.0 million for the year ended December 31, 2014 , as compared to $212.8 million for the year ended December 31, 2013 . Our oil production increase d 56% to over 3.3 million Bbl of oil, or about 9,095 Bbl of oil per day, as compared to approximately 2.1 million Bbl of oil, or about 5,843 Bbl of oil per day, for the year ended December 31, 2013 due to our ongoing development operations in the Eagle Ford shale and from the better-than-expected performance of a number of our initial wells in the Permian Basin. Had the weighted average oil price we realized in 2014 remained consistent with the oil price we realized in 2013, the increase in oil production would have resulted in an increase in oil revenue of $118.5 million , for the year ended December 31, 2014 . This potential increase of $41.2 million in oil revenues was not fully realized in 2014, however, as a result of a lower oil price of $87.37 per Bbl realized for the year ended December 31, 2014 , as compared to $99.79 per Bbl realized for the year ended December 31, 2013 . Our natural gas revenues increase d $21.5 million , or an increase of 38% , to $77.7 million for the year ended December 31, 2014 , as compared to $56.2 million for the year ended December 31, 2013 . Our natural gas production increase d 18% to approximately 15.3 Bcf for the year ended December 31, 2014 , as compared to approximately 12.9 Bcf for the year ended December 31, 2013 due to our ongoing development activities in the Eagle Ford shale and the Permian Basin and to the natural gas production resulting from new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014. This increase in natural gas production in 2014 resulted in increase d natural gas revenues of $10.4 million , and the remaining increase in natural gas revenue of $11.1 million was due to a higher natural gas price of $5.08 per Mcf realized for the year ended December 31, 2014 , as compared to $4.35 per Mcf realized for the year ended December 31, 2013 . +Realized gain (loss) on derivatives . Our realized net gain on derivatives was approximately $5.0 million for the year ended December 31, 2014 , as compared to a realized net loss of approximately $0.9 million for the year ended December 31, +58 +Table of Contents +2013 . We realized a gain from our oil contracts of $5.2 million and a gain of $0.5 million from our natural gas liquids (“NGL”)contracts for the year ended December 31, 2014 due to oil prices being below the floor prices of some of our costless collar contracts and NGL prices being below the fixed prices of some of our swap contracts, respectively, especially during the latter part of 2014. These gain s were partially offset by a loss of approximately $0.7 million on our natural gas contracts due to natural gas prices being in excess of the ceiling prices of our natural gas costless collar contracts, especially in the early months of 2014. Our realized net loss on derivatives was $0.9 million for the year ended December 31, 2013 . We realized a loss from our oil contracts of approximately $2.4 million year ended December 31, 2013 due to oil prices in excess of the ceiling prices of some of our costless collar contracts and the fixed prices of our swap contracts. This loss was partially offset by gains of approximately $0.8 million and $0.7 million on our natural gas and NGL derivative contracts, respectively, due to the respective commodity prices being below the floor prices of our natural gas costless collar contracts and the fixed prices of our NGL swap contracts. We realized an average gain of approximately $2.00 per Bbl hedged on all of our oil costless collar contracts during the year ended December 31, 2014 , as compared to an average loss of $1.42 per Bbl hedged for the year ended December 31, 2013 . Our oil volumes hedged for the year ended December 31, 2014 were also 53% higher as compared to the year ended December 31, 2013 . We realized an average loss of approximately $0.06 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2014 , as compared to an average gain of approximately $0.10 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2013 . Our total natural gas volumes hedged for the year ended December 31, 2014 were also 46% higher than the total natural gas volumes hedged for the year ended December 31, 2013 . +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $58.3 million for the year ended December 31, 2014 , as compared to an unrealized loss of approximately $7.2 million for the year ended December 31, 2013 . During the year ended December 31, 2014 , the net fair value of our open oil, natural gas and natural gas liquids derivatives contracts increase d to approximately $55.5 million , from $(2.8) million for the year ended December 31, 2013 , resulting in an unrealized gain on derivatives of approximately $58.3 million for the year ended December 31, 2014 . During the year ended year ended December 31, 2014 , the net fair value of our open oil, natural gas and NGL derivative contracts increase d by $47.2 million , $9.1 million and $2.0 million , respectively, due primarily to the decrease in the underlying commodities’ futures prices as compared to the year ended December 31, 2013 . +Year Ended December 31, 2013 as Compared to Year Ended December 31, 2012 +Oil and natural gas revenues . Our oil and natural gas revenues increase d by $113.0 million to $269.0 million , or an increase of about 72% , for the year ended December 31, 2013 , as compared to $156.0 million for the year ended December 31, 2012 . This increase in oil and natural gas revenues corresponds with an increase of 30% in our and natural gas production to 4.3 million BOE for the year ended December 31, 2013 , from 3.3 million BOE for the year ended December 31, 2012 . Our oil revenues increase d $89.2 million , or an increase of 72% , to $212.8 million for the year ended December 31, 2013 , as compared to $123.7 million for the year ended December 31, 2012 . Our oil production increase d 76% to over 2.1 million Bbl of oil, or about 5,843 Bbl of oil per day, as compared to approximately 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, for the year ended December 31, 2012 due to our drilling operations in the Eagle Ford shale. The increase in our oil revenues in 2013 was mostly attributable to the increase in oil production, but was partially offset by a slightly lower oil price of $99.79 per Bbl realized for the year ended December 31, 2013 , as compared to $101.86 per Bbl realized for the year ended December 31, 2012 . Our natural gas revenues increase d $23.9 million , an increase of 74% , to $56.2 million for the year ended December 31, 2013 , due to higher prices and increase d production. The vast majority of the increase in natural gas revenues, or $22.7 million , resulted from a significantly higher weighted average natural gas price of $4.35 per Mcf realized during the year ended December 31, 2013 , as compared to a weighted average natural gas price of $2.59 per Mcf realized during the year ended December 31, 2012 . The 3% increase in our natural gas production to approximately 12.9 Bcf for the year ended December 31, 2013 , as compared to approximately 12.5 Bcf for the year ended December 31, 2012 resulted in an increase in natural gas revenues of $1.1 million during 2013 , as compared to 2012 . This slight increase in natural gas production is due to an increase in natural gas production from our Eagle Ford shale wells during 2013 , which was sufficient to offset the decline in natural gas production from our Haynesville and Cotton Valley wells in Northwest Louisiana and East Texas. +Realized gain (loss) on derivatives . Our realized net loss on derivatives was approximately $0.9 million for the year ended December 31, 2013 , as compared to a realized net gain of $14.0 million for the year ended December 31, 2012 . We realized a loss from our oil contracts of approximately $2.4 million for the year ended December 31, 2013 due to oil prices in excess of the ceiling prices of some our costless collar contracts and the fixed prices of our swap contracts. This loss was partially offset by gains of approximately $0.8 million and $0.7 million on our natural gas and NGL contracts, respectively, due to the respective commodity prices being below the floor prices of our natural gas costless collars and the fixed prices of our NGL swap contracts. During the year ended December 31, 2012 , we realized a gain of approximately $2.0 million , $11.9 million and $21,000 on our oil, natural gas and NGL derivative contracts, respectively. These gain s were the result of the respective commodity prices being below the floor and fixed prices of our oil costless collar and swap contracts, natural gas costless collar contracts and NGL swap contracts. We realized an average loss of approximately $1.42 per Bbl hedged on all of +59 +Table of Contents +our oil costless collar and swap contracts during the year ended December 31, 2013 , as compared to an average gain of $1.74 per Bbl hedged for the year ended December 31, 2012 . Our oil volumes hedged for the year ended December 31, 2013 were also 44% higher as compared to the year ended December 31, 2012 . We realized an average gain of approximately $0.10 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2013 , as compared to an average gain of approximately $1.45 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2012 . Our total natural gas volumes hedged for the year ended December 31, 2013 were also 5% higher than the total natural gas volumes hedged for the year ended December 31, 2012 . +Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $7.2 million for the year ended December 31, 2013 , as compared to an unrealized loss of approximately $4.8 million for the year ended December 31, 2012 . During the year ended December 31, 2013 , the net fair value of our open oil, natural gas and natural gas liquids derivative contracts decrease d to approximately $(2.8) million , from approximately $4.5 million , for the year ended December 31, 2012 , resulting in an unrealized loss on derivatives of approximately $7.2 million for the year ended December 31, 2013 . During the year ended December 31, 2013 , the net fair value of our open oil, natural gas and NGL derivative contracts decrease d by $5.3 million , $1.6 million and $0.3 million , respectively, due primarily to the increase in the underlying commodities’ futures prices as compared to the year ended December 31, 2012 . +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2014 +2013 +2012 +(In thousands, except expenses per BOE) +Expenses: +Production taxes and marketing +$ +33,172 +$ +20,973 +$ +11,672 +Lease operating +51,353 +38,720 +28,184 +Depletion, depreciation and amortization +134,737 +98,395 +80,454 +Accretion of asset retirement obligations +504 +348 +256 +Full-cost ceiling impairment +— +21,229 +63,475 +General and administrative +32,152 +20,779 +14,543 +Total expenses +251,918 +200,444 +198,584 +Operating income (loss) +179,118 +60,445 +(33,428 +) +Other (expense) income: +Net loss on asset sales and inventory impairment +— +(192 +) +(485 +) +Interest expense +(5,334 +) +(5,687 +) +(1,002 +) +Interest and other income +1,345 +225 +224 +Total other expense +(3,989 +) +(5,654 +) +(1,263 +) +Income (loss) before income taxes +175,129 +54,791 +(34,691 +) +Total income tax provision (benefit) +64,375 +9,697 +(1,430 +) +Net loss attributable to non-controlling interest in subsidiary +17 +— +— +Net income (loss) attributable to Matador Resources Company shareholders +$ +110,771 +$ +45,094 +$ +(33,261 +) +Expenses per BOE: +Production taxes and marketing +$ +5.65 +$ +4.89 +$ +3.54 +Lease operating +$ +8.75 +$ +9.04 +$ +8.56 +Depletion, depreciation and amortization +$ +22.95 +$ +22.96 +$ +24.43 +General and administrative +$ +5.48 +$ +4.85 +$ +4.42 +Year Ended December 31, 2014 as Compared to Year Ended December 31, 2013 +Production taxes and marketing. Our production taxes and marketing expenses increase d by $12.2 million to $33.2 million , an increase of 58% , for the year ended December 31, 2014 , as compared to $21.0 million for the year ended December 31, 2013 . On a unit-of-production basis, however, our production taxes and marketing expenses increase d by only 16% to $5.65 per BOE for the year ended December 31, 2014 , as compared to $4.89 per BOE for the year ended December 31, 2013 . Much of this increase was attributable to increased production taxes associated with the large increase in our oil production during 2014 resulting from our drilling operations in the Eagle Ford shale, as well as initial production from our newly drilled wells in the Permian Basin. Our total production was comprised of approximately 57% oil and 43% natural gas during the year ended December 31, 2014 , as compared to approximately 50% oil and 50% natural gas during the year ended December 31, 2013 . The increase in production taxes and marketing expenses during the year ended December 31, 2014 also reflected the increase in natural gas production from the Eagle Ford shale where natural gas production taxes are higher than production taxes +60 +Table of Contents +associated with Haynesville shale natural gas in Louisiana, as well as increased marketing expenses on certain of our non-operated Eagle Ford and Haynesville properties in 2014. +Lease operating expenses. Our lease operating expenses increase d by $12.6 million to $51.4 million , an increase of 33% , for the year ended December 31, 2014 , as compared to $38.7 million for the year ended December 31, 2013 . Our lease operating expenses per unit of production decrease d 3% to $8.75 per BOE for the year ended December 31, 2014 , as compared to $9.04 per BOE for the year ended December 31, 2013 . Our total oil and natural gas production increase d 37% to approximately 5.9 million BOE for the year ended December 31, 2014 from approximately 4.3 million BOE for the year ended December 31, 2013 , including an increase of 56% in oil production to over 3.3 million Bbl for the year ended December 31, 2014 , as compared to 2.1 million Bbl for the year ended December 31, 2013 , which would typically result in higher lease operating expenses. Oil production was 57% of total production by volume for the year ended December 31, 2014 , as compared to only 50% of total production by volume for the year ended December 31, 2013 . The decrease achieved in lease operating expenses on a unit-of-production basis was primarily attributable to the progress we have made in reducing our lease operating expenses in the Eagle Ford shale during the last twelve months, which was primarily attributable to (i) the installation of permanent production facilities on almost all of our Eagle Ford properties, alleviating the need for the extended use of flowback equipment to produce newly completed Eagle Ford wells, (ii) the early use of gas lift on most of our newly completed Eagle Ford wells, (iii) a decrease in salt water disposal costs on a per barrel basis, and (iv) continued improvement in overall operational processes in our South Texas operations. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d by $36.3 million to $134.7 million , an increase of 37% , for the year ended December 31, 2014 , as compared to $98.4 million for the year ended December 31, 2013 . On a unit-of-production basis, however, our depletion, depreciation and amortization expenses remained essentially flat at $22.95 per BOE for the year ended December 31, 2014 , as compared to $22.96 per BOE for the year ended December 31, 2013 . The absolute increase in our depletion, depreciation and amortization expenses reflects an increase of approximately 37% in our total oil and natural gas production to 5.9 million BOE for the year ended December 31, 2014 from 4.3 million BOE for the year ended December 31, 2013 . This increase on an absolute basis was offset on a unit-of-production basis by the increase in our proved oil and natural gas reserves of 33% to 68.7 million BOE at December 31, 2014 from 51.7 million BOE at December 31, 2013 . This increase in total proved oil and natural gas reserves was primarily attributable to the continued development of our acreage in the Eagle Ford shale and the initial delineation and development of our acreage in the Permian Basin. As a result of this increase in proved oil and natural gas reserves, depletion, depreciation and amortization expenses on a unit-of production basis remained essentially flat year-over-year. +Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the year ended December 31, 2014 . No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the quarters ended December 31, 2013, September 30, 2013 or June 30, 2013. During the quarter ended March 31, 2013, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . As a result, we recorded an impairment charge of $21.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $7.5 million . This full-cost ceiling impairment of $21.2 million is reflected in our operating expenses for the year ended December 31, 2013 , and resulted primarily from the continued low weighted average index price for natural gas used to estimate proved natural gas reserves at March 31, 2013, which was $2.95 per MMBtu for the period of time from April 2012 through March 2013. +General and administrative. Our general and administrative expenses increase d by $11.4 million to $32.2 million , an increase of 55% , for the year ended December 31, 2014 , as compared to $20.8 million for the year ended December 31, 2013 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses associated with additional personnel joining the Company during the year ended December 31, 2014 to support our increased land, geoscience, drilling, completion and production operations. The remaining increase is largely due to a $1.6 million increase in non-cash stock-based compensation expenses to $5.5 million for the year ended December 31, 2014 , as compared to $3.9 million for the year ended December 31, 2013 . The increase in our non-cash stock-based compensation expense was attributable to the increase d expense related to the continued vesting of awards granted in 2012, 2013 and 2014 of $5.3 million for the year ended December 31, 2014 , as compared to $2.9 million for the year ended December 31, 2013 . This increase was offset by the decrease d expense related to our liability-based stock options of $0.2 million for the year ended December 31, 2014 , as compared to $1.0 million for the year ended December 31, 2013 . This decrease d expense related to our liability-based stock options was attributable to the smaller increase in our stock price from $18.64 per share at December 31, 2013 to $20.23 per share at December 31, 2014 , as compared to the larger increase from $8.20 per share at December 31, 2012 to $18.64 at December 31, 2013 . Our general and administrative expenses increase d by only 13% on a unit-of-production basis to $5.48 per BOE for the year ended December 31, 2014 , as compared to $4.85 for the year ended December 31, 2013 . +61 +Table of Contents +Interest expense. For the year ended December 31, 2014 , we incurred total interest expense of approximately $8.2 million . We capitalized approximately $2.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2014 and expensed the remaining $5.3 million to operations. For the year ended December 31, 2013 , we incurred total interest expense of approximately $7.6 million . We capitalized approximately $1.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2013 and expensed the remaining $5.7 million to operations. The increase in total interest expense for the year ended December 31, 2014 of $0.6 million , as compared to the year ended December 31, 2013 , was primarily attributable to higher average outstanding borrowings under our Credit Agreement during 2014 , as compared to average outstanding borrowings under our Credit Agreement during 2013 . In May 2014, we used a portion of the net proceeds of our public equity offering to repay $180.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2014 , we had $340.0 million in borrowings and $0.6 million in letters of credit outstanding under our Credit Agreement, and the effective interest rate on our borrowings was approximately 3.3% per annum. In September 2013, we used a portion of the net proceeds of our public equity offering to repay $130.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2013 , we had $200.0 million in borrowings and $0.3 million in letters of credit outstanding under our Credit Agreement. +Total income tax provision (benefit) . We recorded a total income tax provision of approximately $64.4 million for the year ended December 31, 2014 , as compared to a total income tax provision of approximately $9.7 million for the year ended December 31, 2013 . For the year ended December 31, 2014 , we incurred an estimated alternative minimum tax (“AMT”) liability of $0.1 million , which represents the current portion of the income tax provision. The remaining income tax provision of $64.2 million represents deferred taxes for the year ended December 31, 2014 . Our effective tax rate for the year ended December 31, 2014 was 36.8% . Total income tax expense for the year ended December 31, 2014 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due to the impact of permanent differences between book and taxable income. For the year ended December 31, 2013 , we incurred an estimated AMT liability of $0.4 million , which represents the current portion of the income tax provision. The remaining $9.3 million represents deferred taxes for the year ended December 31, 2013 . Our effective tax rate for the year ended December 31, 2013 was 17.7% . Total income tax expense for the year ended December 31, 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to (i) the reversal of the valuation allowance of approximately $8.9 million on our federal deferred tax assets at December 31, 2012, as our federal deferred tax liability exceeded our federal deferred tax assets for the year ended December 31, 2013 , (ii) the reversal of a state valuation allowance of approximately $1.3 million , as we believe we will be able to utilize the state net operating losses prior to their expiration, and (iii) the impact of permanent differences between book and taxable income. +Year Ended December 31, 2013 as Compared to Year Ended December 31, 2012 +Production taxes and marketing. Our production taxes and marketing expenses increase d by $9.3 million to $21.0 million , an increase of 80% , for the year ended December 31, 2013 , as compared to $11.7 million for the year ended December 31, 2012 . The majority of this increase was attributable to increase d production taxes associated with the large increase in our oil production during 2013 resulting from our drilling operations in the Eagle Ford shale in South Texas. Our total production was comprised of approximately 50% oil and 50% natural gas during the year ended December 31, 2013 , as compared to approximately 37% oil and 63% natural gas during the year ended December 31, 2012 . On a unit-of-production basis, our our production taxes and marketing expenses increase d by 38% to $4.89 per BOE for the year ended December 31, 2013 , as compared to $3.54 per BOE for the year ended December 31, 2012 . Production taxes on a unit-of-production basis on our oil and natural gas production in Texas are effectively higher than the production taxes on a unit-of-production basis on our production in Louisiana. As a result, the shift in our focus from the Haynesville shale in Northwest Louisiana to the Eagle Ford shale in South Texas has also resulted in an increase in our production taxes. +Lease operating expenses. Our lease operating expenses increase d by $10.5 million to $38.7 million , an increase of 37% , for the year ended December 31, 2013 , as compared to $28.2 million for the year ended December 31, 2012 . Our total oil and natural gas production increased by 30% to approximately 4.3 million BOE for the year ended December 31, 2013 from approximately 3.3 million BOE for the year ended December 31, 2012 , and our oil production increased 76% to over 2.1 million Bbl for the year ended December 31, 2013 , as compared to 1.2 million Bbl for the year ended December 31, 2012 . Our lease operating expenses per unit-of-production increase d 6% to $9.04 per BOE for the year ended December 31, 2013 , as compared to $8.56 per BOE for the year ended December 31, 2012 . This increase in lease operating expenses was primarily attributable to the overall increase in oil and the higher lifting costs associated with oil production between the two years, as well as to the increased percentage of oil being produced, which was approximately 50% of total production by volume for the year ended December 31, 2013 , as compared to 37% of total production by volume for the year ended December 31, 2012 . +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d by $17.9 million to $98.4 million , or an increase of about 22% , for the year ended December 31, 2013 , as compared to $80.5 million for the year ended December 31, 2012 . On a unit-of-production basis, our depletion, depreciation and amortization expenses were +62 +Table of Contents +$22.96 per BOE for the year ended December 31, 2013 , a decrease of 6% , from $24.43 per BOE for the year ended December 31, 2012 . The decrease in our depletion, depreciation and amortization expenses reflects an increase of approximately 30% in our total oil and natural gas production to 4.3 million BOE for the year ended December 31, 2013 from 3.3 million BOE for the year ended December 31, 2012 . Because we use the unit-of-production method for calculating depletion, depreciation and amortization expense, the impact of the increase d production experienced in the year ended December 31, 2013 , as compared to the year ended December 31, 2012 , on our depletion, depreciation and amortization expenses was offset by the increase in our proved oil and natural gas reserves to 51.7 million BOE at December 31, 2013 from 23.8 million BOE at December 31, 2012 . Primarily as a result of continued improvement in natural gas prices over the past year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013. We had removed a large portion of these proved undeveloped natural gas reserves from our estimated total proved reserves at June 30, 2012 because the unweighted arithmetic average natural gas price had declined to $3.146 per MMBtu, a price at which the natural gas volumes associated with almost all of our identified Haynesville shale well locations could no longer be classified as proved undeveloped reserves. +Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the quarters ended December 31, 2013, September 30, 2013 or June 30, 2013. During the quarter ended March 31, 2013, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . As a result, we recorded an impairment charge of $21.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $7.5 million . This full-cost ceiling impairment of $21.2 million is reflected in our operating expenses for the year ended December 31, 2013 , and resulted primarily from the continued low weighted average index price for natural gas used to estimate proved natural gas reserves at March 31, 2013, which was $2.95 per MMBtu for the period of time from April 2012 through March 2013. At June 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . As a result, we recorded an impairment charge of $33.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $11.9 million . At September 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . As a result, we recorded an impairment charge of $3.6 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $1.3 million . At December 31, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million . As a result, we recorded an impairment charge of $26.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $9.4 million . These full-cost ceiling impairment charges in 2012 were primarily attributable to declining natural gas prices throughout much of the year. As a result of substantially lower natural gas prices in 2012 , we had downward revisions of our natural gas reserves totaling 103.4 Bcf (17.2 million BOE), including the removal of 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012. These impairment charges are reflected in our operating expenses for the year ended December 31, 2012 . +General and administrative. Our general and administrative expenses increase d by $6.2 million to $20.8 million , or an increase of 43% , for the year ended December 31, 2013 , as compared to $14.5 million for the year ended December 31, 2012 . The increase in our general and administrative expenses was primarily attributable to a $3.8 million increase in stock-based compensation costs to $3.9 million for the year ended December 31, 2013 , as compared to $0.1 million for the year ended December 31, 2012 . The increase in our stock-based compensation expense was primarily attributable to the continued vesting of awards granted in 2012 and 2013, as well as the increase d fair value of our liability-based stock options during the year ended December 31, 2013 due to the increase in our stock price from $8.20 per share at December 31, 2012 to $18.64 per share at December 31, 2013 . The remaining increase in our general and administrative expenses was primarily due to additional payroll expenses associated with personnel added between the respective periods to support our increased operations, some of which was offset by $1.0 million of our general and administrative expenses for the year ended December 31, 2013 that was capitalized in connection with the permanent production facilities being constructed on certain of our properties in the Eagle Ford shale in South Texas during the second quarter of 2013. Our general and administrative expenses increase d by only 10% on a unit-of-production basis to $4.85 per BOE for the year ended December 31, 2013 , as compared to $4.42 per BOE for the year ended December 31, 2012 . On a unit-of-production basis, the increase in general and administrative expenses was partially offset by the increase of approximately 30% in our total oil and natural gas production to 4.3 million BOE from 3.3 million BOE during the respective periods. +Interest expense. For the year ended December 31, 2013 , we incurred total interest expense of approximately $7.6 million . We capitalized approximately $1.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2013 and expensed the remaining $5.7 million to operations. For the year ended December 31, 2012 , we incurred total interest expense of approximately $2.6 million . We capitalized approximately $1.6 million of our interest expense +63 +Table of Contents +on certain qualifying projects for the year ended December 31, 2012 and expensed the remaining $1.0 million to operations. The increase in interest expense for the year ended December 31, 2013 of $4.7 million , as compared to the year ended December 31, 2012 , was primarily attributable to higher average outstanding borrowings under our Credit Agreement during 2013 , as compared to average outstanding borrowings under our Credit Agreement during 2012 . In September 2013, we used a portion of the net proceeds of our public equity offering to repay $130.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2013 , we had $200.0 million in borrowings and $0.3 million in letters of credit outstanding under our Credit Agreement, and the effective interest rate on our borrowings was approximately 3.3% per annum. In February 2012, we used a portion of the net proceeds of our Initial Public Offering to repay our then outstanding borrowings of $123.0 million . At December 31, 2012 , we had $150.0 million in borrowings and $1.1 million in letters of credit outstanding under our Credit Agreement. +Total income tax provision (benefit) . We recorded a total income tax benefit of approximately $9.7 million for the year ended December 31, 2013 , as compared to a total income tax benefit of approximately $1.4 million for the year ended December 31, 2012 . For the year ended December 31, 2013 , we incurred an estimated AMT liability of $0.4 million , which represents the current portion of the income tax provision. The remaining tax provision of $9.3 million represents deferred taxes for the year ended December 31, 2013 . Our effective tax rate for the year ended December 31, 2013 was 17.7% . Total income tax expense for the year ended December 31, 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to (i) the reversal of the valuation allowance of approximately $8.9 million on our federal deferred tax assets at December 31, 2012 , as our federal deferred tax liability exceeded our federal deferred tax assets for the year ended December 31, 2013 , (ii) the reversal of a state valuation allowance of approximately $1.3 million , as we now believe we will be able to utilize the state net operating losses prior to their expiration, and (iii) the impact of permanent differences between book and taxable income. During the year ended December 31, 2012 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $40.9 million . We recorded an impairment charge of $63.5 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $22.6 million . The increase in our deferred tax assets as a result of the impairment charges recorded during the year ended December 31, 2012 caused our deferred tax assets to exceed our deferred tax liabilities, resulting in the establishment of a valuation allowance of $10.3 million due to uncertainties regarding the future realization of our deferred tax assets. As a result, we recorded an income tax benefit of $1.4 million for the year ended December 31, 2012 . We had a net loss for the year ended December 31, 2012. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2015 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including additional borrowings, equity and debt financings and joint ventures, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows. +At December 31, 2014 , we had cash totaling approximately $8.4 million , the borrowing base under our Credit Agreement was $450.0 million , and we had $340.0 million of outstanding long-term borrowings and approximately $0.6 million in outstanding letters of credit. These borrowings bore interest at an effective interest rate of approximately 3.3% per annum. From January 1 through February 27, 2015 , we borrowed an additional $55.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures, to acquire additional leasehold interests and to consummate the HEYCO Merger. At February 27, 2015 , following the closing of the HEYCO Merger, we had $395.0 million of outstanding long-term borrowings and approximately $0.6 million in outstanding letters of credit under the Credit Agreement and an additional $12.0 million of borrowings that was assumed in connection with the HEYCO Merger. +On May 29, 2014, we completed a public offering of 7,500,000 shares of our common stock. After deducting direct offering costs totaling approximately $0.6 million , we received net proceeds of approximately $181.3 million . We used a portion of the net proceeds to repay $180.0 million in outstanding borrowings under the Credit Agreement, which amounts were subsequently reborrowed in accordance with the terms of that facility. The remaining $1.3 million of the offering net proceeds was used to fund working capital requirements. +Our 2015 capital expenditure budget is estimated to be $350.0 million (excluding capital expenditures associated with the HEYCO Merger) and includes approximately $267.0 million for drilling and completing oil and natural gas exploration and development wells, with the remainder allocated to lease acquisitions, seismic data, midstream initiatives, pipelines and other infrastructure. Due to the sharp decline in oil and natural gas prices since mid- 2014 , we have reduced our estimated capital expenditure budget by approximately 43% from the $610.4 million in capital expenditures we incurred in 2014 . We were operating five drilling rigs, two rigs in the Eagle Ford and three rigs in the Permian Basin, at the beginning of 2015 , but plan to reduce our operated drilling rigs to two, both operating in the Permian Basin, during the second quarter of 2015 . We then plan +64 +Table of Contents +to operate two drilling rigs in the Permian Basin for the remainder of 2015 . We plan to temporarily suspend our drilling program in the Eagle Ford shale for the balance of 2015 or until commodity prices increase sufficiently. We expect to fund our 2015 capital expenditure budget through a combination of operating cash flows, borrowings under our Credit Agreement (assuming availability under our borrowing base) or additional credit arrangements, potential joint ventures, the sale of assets or acreage and potential issuances of equity or debt securities, which may not be available on terms reasonably acceptable to us or at all. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate and could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our Credit Agreement. A significant portion of our anticipated cash flows from operations in 2015 is expected to come from producing wells and development activities on currently proved properties in the Eagle Ford shale in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin and the Haynesville shale in Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2015 and the hedges we currently have in place. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. At February 27, 2015 , we have approximately 40% of our anticipated oil production and approximately 70% of our anticipated natural gas production hedged for the remainder of 2015 . We currently have no hedges in place for oil or natural gas beyond 2015. +Due to the sharp decline in commodity prices since mid- 2014 , we anticipate that our operating cash flows in 2015 will be less than in 2014 . Further, if our exploration, development and production activities result in less cash flows than anticipated, we may seek additional sources of capital, including through additional borrowings under our Credit Agreement, additional debt arrangements, the sale of assets or acreage or entering into one or more joint ventures, none of which may be available. In addition to future borrowings under our Credit Agreement, we may also seek to raise additional funds by issuing debt securities or selling shares of our common stock or securities convertible or exercisable into our common stock (including debt securities or other preferential securities) in the public markets or otherwise. Any such sales of equity or convertible securities would dilute the ownership interest of our existing shareholders. There is no guarantee that we would be able to sell such debt or equity securities on terms acceptable to us. It is also possible that, to the extent we are not able to obtain additional sources of capital, we may modify our planned capital expenditure budget for 2015 accordingly to further reduce our capital spending and rate of growth or enter into one or more joint ventures or other alternative financings. Exploration and development activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and the borrowing base under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” +Our cash flows for the years ended December 31, 2014, 2013 and 2012 are presented below: +Year Ended December 31, +2014 +2013 +2012 +(In thousands) +Net cash provided by operating activities +$ +251,481 +$ +179,470 +$ +124,228 +Net cash used in investing activities +(570,531 +) +(366,939 +) +(306,916 +) +Net cash provided by financing activities +321,170 +191,661 +174,499 +Net change in cash +$ +2,120 +$ +4,192 +$ +(8,189 +) +Cash Flows Provided by Operating Activities +Net cash provided by operating activities increased by $72.0 million to $251.5 million for the year ended December 31, 2014 , as compared to net cash provided by operating activities of $179.5 million for the year ended December 31, 2013 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $257.5 million for the year ended December 31, 2014 from $185.7 million for the year ended December 31, 2013 . This increase is primarily attributable to the increase of approximately 56% in our oil production to just over 3.3 million Bbl from approximately 2.1 million Bbl during the respective periods. Changes in our operating assets and liabilities between +65 +Table of Contents +December 31, 2013 and December 31, 2014 also resulted in a net increase of approximately $0.2 million in net cash provided by operating activities for the year ended December 31, 2014 , as compared to the year ended December 31, 2013 . +Net cash provided by operating activities increased by $55.2 million to $179.5 million for the year ended December 31, 2013 , as compared to net cash provided by operating activities of $124.2 million for the year ended December 31, 2012 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $185.7 million for the year ended December 31, 2013 from $114.9 million for the year ended December 31, 2012 . This increase is primarily attributable to the increase of approximately 76% in our oil production to just over 2.1 million Bbl from approximately 1.2 million Bbl during the respective periods. Changes in our operating assets and liabilities between December 31, 2013 and December 31, 2012 also resulted in a net decrease of approximately $15.5 million in net cash provided by operating activities for the year ended December 31, 2013 , as compared to the year ended December 31, 2012 . +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service agreements in order to minimize ongoing future commitments. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities increased by $203.6 million to $570.5 million for the year ended December 31, 2014 from $366.9 million for the year ended December 31, 2013 . This increase in net cash used in investing activities reflected an increase of $197.7 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2014 , as compared to the year ended December 31, 2013 , and an increase of approximately $5.2 million in expenditures for other property and equipment, which includes new pipeline infrastructure associated primarily with our properties in the Eagle Ford shale, but also reflects initial costs associated with a natural gas processing plant and a saltwater disposal facility we are constructing in Loving County, Texas. Approximately 87% of our capital expenditures were allocated to drilling and completion operations, associated infrastructure and midstream activities and 13% to the acquisition of additional acreage for the year ended December 31, 2014 , as compared to approximately 83% allocated to drilling and completion operations and associated infrastructure and 17% allocated to acquisition of additional acreage for the year ended December 31, 2013 . Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2014 was primarily attributable to our operated and non-operated drilling and completion activities in the Eagle Ford shale play, as well as to our operated drilling activities in the Permian Basin and certain non-operated drilling activities in the Haynesville shale. We also used a portion of this cash to acquire approximately 29,300 gross (21,800 net) acres in the Permian Basin in 2014, along with 3,200 gross (3,000 net) acres in the Eagle Ford shale. +Net cash used in investing activities increased by $60.0 million to $366.9 million for the year ended December 31, 2013 from $306.9 million for the year ended December 31, 2012 . This increase in net cash used in investing activities reflected an increase of $62.5 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2013 , as compared to the year ended December 31, 2012 , and a decrease of approximately $3.4 million in expenditures for other property and equipment, which included new pipeline infrastructure associated with our properties in the Eagle Ford shale. Approximately 83% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 17% to the acquisition of additional acreage for the year ended December 31, 2013 , as compared to approximately 91% allocated to drilling and completion operations and associated infrastructure and 9% allocated to acquisition of additional acreage for the year ended December 31, 2012 . Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2013 was primarily attributable to our operated and non-operated drilling and completion activities in the Eagle Ford shale play, as well as to our initial operated drilling activities in the Permian Basin. We also used a portion of this cash to acquire approximately 55,400 gross (38,900 net) additional acres in the Permian Basin during 2013, along with approximately 1,720 gross (1,660 net) acres in the Eagle Ford shale and 1,190 gross (1,190) net acres in the Haynesville shale. +66 +Table of Contents +Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing approximately $350.0 million in capital (excluding capital expenditures associated with the HEYCO Merger) for acquisition, exploration and development activities in 2015 as follows: +Amount +(in millions) +Exploration and development drilling and completion costs +$ +267.0 +Midstream activities +38.0 +Pipeline and infrastructure expenditures +25.0 +Leasehold acquisition and 2-D and 3-D seismic data +20.0 +Total +$ +350.0 +For further information regarding our anticipated 2015 capital expenditure budget, see “Business — General.” +Our 2015 capital expenditures may be adjusted as business conditions warrant, as evidenced by the substantial reduction in our 2015 capital expenditures budget, as compared to our 2014 capital spending, in response to the sharp decline in oil and natural gas prices since mid- 2014 . The amount, timing and allocation of our capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline further or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later periods to conserve cash or to focus on those projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $321.2 million for the year ended December 31, 2014 , as compared to net cash provided by financing activities of $191.7 million for the year ended December 31, 2013 . The net cash provided by financing activities for the year ended December 31, 2014 was primarily attributable to the total proceeds of our May 2014 public equity offering of $181.9 million and borrowings under our Credit Agreement of $320.0 million , offset by the costs of the offering of $0.6 million paid during the period and by the repayment of $180.0 million in borrowings under our Credit Agreement during the period. +Net cash provided by financing activities was $191.7 million for the year ended December 31, 2013 , as compared to net cash provided by financing activities of $174.5 million for the year ended December 31, 2012 . The net cash provided by financing activities for the year ended December 31, 2013 was primarily attributable to the total proceeds from our September 2013 public equity offering of $149.1 million and borrowings of $180.0 million under our Credit Agreement during the period, offset by the costs of the offering of $7.4 million incurred during the period and by the repayment of $130.0 million in borrowings under our Credit Agreement during the period. +Net cash provided by financing activities was $174.5 million for the year ended December 31, 2012 . The net cash provided by financing activities for the year ended December 31, 2012 was principally due to the total proceeds from the Initial Public Offering of $146.5 million and total borrowings of $160.0 million under our Credit Agreement to fund a portion of our working capital requirements during the period, offset by the costs of the Initial Public Offering of $11.6 million incurred during the period and by the repayment of $123.0 million in borrowings during the period. We also received approximately $2.7 million from the exercise of stock options during the year ended December 31, 2012 . +Credit Agreement +On September 28, 2012, we entered into the Credit Agreement, which increased the maximum facility amount from $400.0 million to $500.0 million . The Credit Agreement matures December 29, 2016. Our subsidiary, MRC Energy Company, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of our oil and natural gas properties, other than those properties acquired in the HEYCO Merger (which properties secure the approximately $12.0 million in indebtedness we assumed in the HEYCO Merger) and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. +67 +Table of Contents +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2014 , our lenders completed their review of our estimated total proved oil and natural gas reserves at December 31, 2013 , and on March 12, 2014 , the borrowing base under our Credit Agreement was increased to $385.0 million , and the conforming borrowing base was increased to $310.0 million . At that time, Wells Fargo, N.A. replaced Capital One, N.A. in our lending group, and we amended the Credit Agreement to, among other things, provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by us of senior unsecured notes in an amount greater than or equal to $10.0 million . The Credit Agreement was also amended to eliminate the current ratio covenant and to increase the debt to EBITDA ratio covenant, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, to 4.25 or less. Furthermore, the interest rate charged to us based on our outstanding level of borrowings was reduced by 0.25% across the borrowing grid as a result of this amendment. This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. +During the third quarter of 2014 , the lenders completed their review of our estimated total proved oil and natural gas reserves at July 31, 2014, and on September 5, 2014, the borrowing base under our Credit Agreement was increased to $450.0 million, and the conforming borrowing base was increased to $375.0 million. This September 2014 redetermination constituted the regularly scheduled November 1 redetermination. We may request one additional unscheduled redetermination of our borrowing base prior to the next scheduled redetermination. +At February 27, 2015 , the Lenders had begun the regularly scheduled May 1 redetermination of our borrowing base using our estimated total proved oil and natural gas reserves at December 31, 2014 . Oil and natural gas prices have declined significantly in the six months since the last borrowing base redetermination in September 2014 . As a result, the Company cannot be certain as to how much, if any, increase in its borrowing base may be achieved from this May 1 redetermination. +In the event of a borrowing base increase, we are required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months. +At December 31, 2014 , we had $340.0 million in borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. At December 31, 2014 , our outstanding borrowings bore interest at an effective interest rate of approximately 3.3% per annum. From January 1, 2014 through February 27, 2015 , we borrowed an additional $55.0 million under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures, to acquire additional leasehold interests and to consummate the HEYCO Merger. At February 27, 2015 , following the closing of the HEYCO Merger, we had $395.0 million of outstanding long-term borrowings and approximately $0.6 million in outstanding letters of credit under the Credit Agreement and an additional approximately $12.0 million in indebtedness that we assumed in connection with the HEYCO Merger. We expect to access future borrowings under our Credit Agreement to fund a portion of our 2015 capital expenditure requirements in excess of amounts available from our operating cash flows. +If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 3.75% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by us. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. We include this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in our interest rate calculations and related disclosures. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. +68 +Table of Contents +Subject to certain exceptions, our Credit Agreement contains various covenants that limit our ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of our assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; and +• +engage in certain asset dispositions, including a sale of all or substantially all of our assets. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving us or our subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +During the second quarter of 2014, Bank of America, N.A. replaced Citibank, N.A. as a lender under the Credit Agreement. +At December 31, 2014 , we believe that we were in compliance with the terms of our Credit Agreement. +Off-Balance Sheet Arrangements +From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2014 , the material off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements, (ii) non-operated drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) firm transportation and fractionation commitments, (v) agreements to construct facilities and (vi) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. See “Obligations and Commitments” below and “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K for more information regarding the Company's off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2014 : +69 +Table of Contents +Payments Due by Period +Total +Less Than 1 Year +1-3 Years +3-5 Years +More Than 5 Years +(In thousands) +Contractual Obligations: +Revolving credit borrowings and term loan, including letters of credit (1) +$ +340,600 +$ +— +$ +340,600 +$ +— +$ +— +Office lease +7,047 +971 +1,790 +1,868 +2,418 +Non-operated drilling commitments (2) +20,983 +20,983 +— +— +— +Drilling rig contracts (3) +50,351 +28,388 +21,963 +— +— +Asset retirement obligations +11,951 +311 +900 +2,897 +7,843 +Natural gas processing and transportation agreement (4) +5,988 +2,992 +2,996 +— +— +Gas plant engineering, procurement, construction and installation contract (5) +14,900 +14,900 +— +— +— +Total contractual cash obligations +$ +451,820 +$ +68,545 +$ +368,249 +$ +4,765 +$ +10,261 +__________________ +(1) +At December 31, 2014 , we had $340.0 million in revolving borrowings outstanding under our Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. These borrowings mature in December 2016. These amounts do not include estimated interest on the obligations, because our revolving borrowings had short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods. +(2) +At December 31, 2014 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2014 . If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $21.0 million at December 31, 2014 , which we expect to incur within the next year. +(3) +We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of our commitments for the drilling services to be provided, which have typically been for one year or less, although in 2014, we entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were experiencing heavy demand for drilling rigs. Should we elect to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure work for the contracted drilling rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate termination obligations under our drilling rig contracts were approximately $50.4 million at December 31, 2014 . +(4) +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. The undiscounted minimum commitments under this agreement total approximately $6.0 million at December 31, 2014 . +(5) +We entered into an agreement with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in Loving County, Texas in 2014. This plant is expected to process a portion of our natural gas produced from certain of our wells in the Permian Basin, as well as third-party natural gas. The plant is scheduled to be completed and placed in service in the third quarter of 2015. +General Outlook and Trends +For the year ended December 31, 2014 , oil prices ranged from a high of approximately $107.26 per Bbl in mid-June to a low of approximately $53.27 per Bbl in late December, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $87.37 per Bbl ( $88.94 per Bbl including realized gains from oil derivatives) for our oil production for the year ended December 31, 2014 , as compared to $99.79 per Bbl ( $98.67 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2013 . At February 27, 2015 , the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had declined further, closing at $49.76 per Bbl, as compared to $102.40 per Bbl at February 27, 2014 . +For the year ended December 31, 2014 , natural gas prices ranged from a high of approximately $6.15 per MMBtu in mid-February to a low of approximately $2.89 per MMBtu in late December, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $5.08 per Mcf ( $5.06 per Mcf including realized losses from natural gas and NGL derivatives) for our natural gas production for the year ended December 31, 2014 , as compared to $4.35 per Mcf ( $4.47 per Mcf including realized gains from natural gas and NGL derivatives) for the year ended December 31, 2013 . At February 27, 2015 , the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had declined further, closing at $2.73 per MMBtu, as compared to $4.51 per MMBtu at February 27, 2014 . +In response to the sharp decrease in oil and natural gas prices experienced in late 2014 and early 2015 , we have reduced our 2015 estimated capital expenditure budget to $350.0 million (excluding capital expenditures associated with the HEYCO Merger), as compared to actual capital expenditures of $610.4 million for the year ended December 31, 2014 . This 2015 capital expenditure budget anticipates a reduction of our drilling program from five drilling rigs operating in January 2015 to two +70 +Table of Contents +drilling rigs by the second quarter of 2015 . We then plan to operate these two drilling rigs on our Permian Basin properties throughout the remainder of 2015 . We also plan to temporarily suspend our development drilling program in the Eagle Ford shale after the first quarter of 2015 , as approximately 96% of our Eagle Ford acreage was held by production or not burdened by lease expirations until 2016 at December 31, 2014 . We would not expect to increase our operated drilling activities in either the Eagle Ford shale or the Permian Basin until oil prices improve sufficiently from their current levels. We also plan to direct a small portion of our 2015 capital expenditures, about 4%, to our participation in non-operated Haynesville shale wells in Northwest Louisiana. +Coincident with the recent decline in commodity prices, we have also begun to experience price reductions from our service providers for many of the products and services we use in our drilling and completion operations. At February 27, 2015 , we were receiving price reductions of approximately 15% to 20% on many of the products and services we use, but we have also begun to see some price reductions as high as 50% on certain products and services. If oil and natural gas prices remain at their current levels for an extended period of time or should they decline further, we would anticipate receiving additional price reductions for drilling and completion products and services, although we can provide no assurances that these price reductions will occur or of their eventual magnitude. +Most of our Eagle Ford shale oil production in South Texas is sold based on a Louisiana Light Sweet oil price index less transportation costs. Although we realized significant uplifts to West Texas Intermediate oil prices at times during 2013, the differential between these two benchmark prices has decreased since early 2013. We may not realize similar, or any, uplifts to West Texas Intermediate oil prices in future periods, which could result in a decrease in our weighted average oil price realized and associated oil revenues. Additionally, oil production from our properties in the Permian Basin is sold on a West Texas Intermediate oil price index less transportation costs. +The prices we receive for oil, natural gas and natural gas liquids heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and natural gas liquids are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or natural gas liquids prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and natural gas liquids we can produce economically. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and natural gas liquids price declines, however, drilling additional oil or natural gas wells may not be economical, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our +71 +Table of Contents +estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See “Note 2 — Summary of Significant Accounting Policies” to the consolidated financial statements in this Annual Report on Form 10-K for further details on our accounting policies at December 31, 2014 . Such information is incorporated herein by reference. +Property and Equipment +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred. These costs are accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling”. The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using commodity prices that represent the arithmetic averages of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period, and the guidelines further dictate that a 10% discount factor be used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related reserves. +Because of the volatile nature of oil and gas prices, it generally is not possible to predict the timing or magnitude of full-cost impairments. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full-cost ceiling impairment. +Although uncertain future oil and natural gas prices impact the ability to predict future full-cost ceiling impairments, we do anticipate recognizing full-cost ceiling impairments in 2015, beginning as early as the first quarter of 2015. This conclusion is based on the historic commodity prices for the last nine months of 2014 and the first two months of 2015 as well as the short-term pricing outlook. Although we can predict with relative certainty that we will recognize full-cost ceiling impairments in 2015, we are not able to reasonably estimate the amounts of any such impairments. However, we expect the amounts, if realized, will be material to our net income and earnings per share but will have no impact on our cash flows from operations, liquidity or capital resources. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. +Impairment +72 +Table of Contents +Unproved and unevaluated properties are assessed for impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statement of operations. Such changes in fair value are reported under “Revenue” as “Unrealized gain (loss) on derivatives”. Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flow from operations, liquidity or capital resources. The fair value of our derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under “Revenue” as “Realized gain (loss) on derivatives”. +Revenue Recognition +We follow the sales method of accounting for our oil, natural gas and natural gas liquids revenue, whereby we recognize revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural gas and natural gas liquids are produced and sold, and we accrue for revenue earned but not yet received. +Stock-Based Compensation +We account for stock-based compensation in accordance with ASC 718. During 2014 , 2013 and 2012 all stock option awards were granted under our 2012 Long-Term Incentive Plan and were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these awards have been accounted for as liability instruments. We used the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, we estimated the future volatility of our stock using the historical volatility of the common stock of a group of companies we consider to be a representative peer group. Management believes that these average historical volatility rates are currently the best available indicator of future volatility. +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards are recognized based on the fair value of our stock on the date of the grant. See “Note 8 — Stock-Based Compensation” to the consolidated financial statements in this Annual +73 +Table of Contents +Report on Form 10-K for further details on our stock-based compensation at December 31, 2014. Such information is incorporated herein by reference. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report on Form 10-K. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” +Recent Accounting Pronouncements +Revenue from Contracts with Customers. In May 2014, the FASB issued Accounting Standards Update, or ASU, 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. ASU 2014-09 will become effective for fiscal years beginning after December 15, 2016, i.e., in our first fiscal quarter of 2017. We are currently evaluating the impact, if any, of the adoption of this ASU on our consolidated financial statements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and natural gas liquids fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our future anticipated production. +74 +Table of Contents +We use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2014 , RBC, Comerica Bank, The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +We have entered into various costless collar contracts to mitigate our exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these oil hedging transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. +We have entered into various costless collar contracts to mitigate our exposure to fluctuations in natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. +We have entered into various swap contracts to mitigate our exposure to fluctuations in NGL prices, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to us pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity on the pricing date. When the settlement price is below the fixed price established by one or more of these swaps, we receive from our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, we pay to our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. +See “Note 11 — Derivative Financial Instruments” to the consolidated financial statements in this Annual Report on Form 10-K for a summary of our open derivative financial instruments at December 31, 2014 . Such information is incorporated herein by reference. +Effect of Recent Derivatives Legislation. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has proposed or finalized most of these regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” +75 +Table of Contents +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2014 we had $340.0 million in revolving borrowings outstanding under our Credit Agreement at an interest rate of approximately 3.3% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our oil, natural gas and natural gas liquids derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 27, 2015 were RBC, Comerica Bank, The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) and we are likely to enter into any future derivative instruments with RBC, Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2014, 2013 and 2012 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Eagle Ford shale play, the Wolfcamp and Bone Spring plays in the Permian Basin, and the Haynesville shale play. See “Business — General.” See also “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report on Form 10-K. See the index to the financial statements in Item 15. +Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. +On April 9, 2014, the Audit Committee of the Board of Directors of the Company approved the appointment of KPMG LLP (“KPMG”) as the Company’s independent registered public accounting firm for the year ending December 31, 2014. This appointment constituted the dismissal of Grant Thornton LLP (“Grant Thornton”) as the Company’s independent registered public accounting firm. Grant Thornton completed its engagement as the Company’s independent registered public accounting firm for the year ended December 31, 2013 upon the filing of the Company’s Annual Report on Form 10-K. The Audit Committee made its decision in connection with its annual review of the Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms. +Grant Thornton’s audit reports on the Company’s consolidated financial statements for the years ended December 31, 2013 and 2012 did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principles. +During the years ended December 31, 2013 and 2012, and through the current date, there were no (i) disagreements (as defined in Item 304(a)(1)(iv) of Regulation S-K) between the Company and Grant Thornton on any matter of accounting principle or practice, financial statement disclosure, or auditing scope or procedure which, if not resolved to Grant Thornton’s +76 +Table of Contents +satisfaction, would have caused it to make reference to the matter in conjunction with its report on the Company’s consolidated financial statements for the relevant year, or (ii) reportable events (as defined in Item 304(a)(1)(v) of Regulation S-K). +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2014 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2014 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +77 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2014 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of the Company and subsidiaries as of December 31, 2014 , and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the year then ended, and our report dated March 2, 2015 expressed an unqualified opinion on those consolidated financial statements. +/s/ KPMG LLP +Dallas, Texas +March 2, 2015 +78 +Table of Contents +Item 9B. Other Information. +On February 26, 2015, we entered into an amendment to the Independent Contractor Agreement with David F. Nicklin and his consulting company, David F. Nicklin International Consulting, Inc. (the “Independent Contractor Agreement Amendment”). Pursuant to the Independent Contractor Agreement Amendment, the term of Mr. Nicklin’s Independent Contractor Agreement was extended to March 31, 2015 with automatic monthly extensions thereafter unless either party elects to terminate the agreement upon notice provided not less than fifteen days before the end of the then-current month. In addition, the daily rate paid to Mr. Nicklin was increased to $2,000 per full business day worked. This description of the Independent Contractor Agreement Amendment is qualified in its entirety by reference to the Independent Contractor Agreement Amendment, a copy of which is filed as an exhibit to this Annual Report on Form 10-K and is incorporated herein by reference. +On February 26, 2015 and February 27, 2015, we borrowed $15.0 million and $10.0 million, respectively, under the Credit Agreement to finance a portion of the HEYCO Merger and for our other working capital requirements and capital expenditures. As of February 27, 2015, we had $395.0 million in borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. As of February 27, 2015, the conforming borrowing base under the Credit Agreement was $375.0 million and the borrowing base under the Credit Agreement was $450.0 million. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. As of February 27, 2015, we had $54.4 million available for additional borrowings under the Credit Agreement. The Company anticipates borrowing additional amounts under the Credit Agreement to fund its existing working capital requirements and capital expenditures. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report on Form 10-K and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +79 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report on Form 10-K: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2014 and 2013 , Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 . +2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K. +80 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011). +2.2 +Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 20, 2015).* +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (filed herewith). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (filed herewith). +2.5 +Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (filed herewith).* +2.6 +Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on March 2, 2015).* +3.1 +Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011). +3.2 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13, 2012). +3.3 +Amended and Restated Bylaws of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on February 13, 2012). +3.4 +Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on March 2, 2015). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 2, 2015). +4.3 +Voting Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on March 2, 2015). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +Independent Contractor Agreement between Matador Resources Company and David F. Nicklin (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +81 +Table of Contents +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.8† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.9† +First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.10† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.11† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.12† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.13† +Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.14† +First Amendment to the Independent Contractor Agreement between Matador Resources Company and David F. Nicklin (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.15† +2012 Long-Term Incentive Plan of Matador Resources Company (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.16† +First Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated April 16, 2012 (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.17† +Second Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated March 8, 2013 (incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.18† +Matador Resources Company Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.19† +Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.20† +First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.21† +Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.22† +Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.23† +Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +82 +Table of Contents +10.24† +Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.25† +Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.26† +Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.27† +Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.28† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.29 +Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011 (incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.30 +First Amendment to Purchase Sale and Participation Agreement, dated as of June 12, 2013, by and between MRC Energy Company and Orca/ICI Development (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.31† +Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.32† +Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.33† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.34† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.35† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.36† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.37† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.38† +Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.39† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.40† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +83 +Table of Contents +10.41† +Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.42 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.43 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.44 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.45 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.46 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.47 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.48 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.49 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.50† +Form of Employment Agreement between Matador Resources Company and each of Craig N. Adams and Ryan C. London (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.51† +Letter Agreement between Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., dated February 26, 2015 (filed herewith). +10.52† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (filed herewith). +10.53 +Guaranty, dated February 27, 2015, by Matador Resources Company in favor of PlainsCapital Bank (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 2, 2015). +10.54† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith). +10.55† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Grant Thornton LLP (filed herewith). +23.3 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +84 +Table of Contents +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +† +Indicates a management contract or compensatory plan or arrangement. +* +Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +85 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +March 2, 2015 +By: +/s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Joseph Wm. Foran +Chairman and Chief Executive Officer (Principal Executive Officer) +March 2, 2015 +Joseph Wm. Foran +/s/ David E. Lancaster +Executive Vice President, +Chief Operating Officer and +Chief Financial Officer +(Principal Financial Officer) +March 2, 2015 +David E. Lancaster +/s/ Sandra K. Fendley +Vice President and Chief Accounting Officer (Principal Accounting Officer) +March 2, 2015 +Sandra K. Fendley +/s/ Reynald A. Baribault +Director +March 2, 2015 +Reynald A. Baribault +/s/ David M. Laney +Director +March 2, 2015 +David M. Laney +/s/ Gregory E. Mitchell +Director +March 2, 2015 +Gregory E. Mitchell +/s/ Steven W. Ohnimus +Director +March 2, 2015 +Steven W. Ohnimus +/s/ Michael C. Ryan +Director +March 2, 2015 +Michael C. Ryan +/s/ Carlos M. Sepulveda, Jr. +Director +March 2, 2015 +Carlos M. Sepulveda, Jr. +/s/ Margaret B. Shannon +Director +March 2, 2015 +Margaret B. Shannon +86 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report on Form 10-K in reference to crude oil or other liquid hydrocarbons. +Bcf . One billion cubic feet. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +FERC . Federal Energy Regulatory Commission. +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may +87 +Table of Contents +also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil or other liquid hydrocarbons. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +88 +Table of Contents +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such property to be classified as proved. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +89 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2014, 2013 and 2012 +Contents +Reports of Independent Registered Public Accounting Firms +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2014 and 2013 +F-4 +Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012 +F-5 +Consolidated Statements of Changes in Shareholders' Equity for the Years Ended December 31, 2014, 2013 and 2012 +F-6 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 +F- 7 +Notes to Consolidated Financial Statements +F-7 +Unaudited Supplementary Information +F-42 +F- 1 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited the accompanying consolidated balance sheet of Matador Resources Company (a Texas corporation) and subsidiaries (collectively the “Company”) as of December 31, 2014 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for the year ended December 31, 2014 . These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Matador Resources Company and subsidiaries as of December 31, 2014 and the results of their operations and their cash flows for the year ended December 31, 2014 in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014 , based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +/s/ KPMG LLP +Dallas, Texas +March 2, 2015 +F- 2 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Shareholders +Matador Resources Company +We have audited the accompanying consolidated balance sheet of Matador Resources Company (a Texas corporation) and subsidiaries (collectively the “Company”) as of December 31, 2013, and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Matador Resources Company and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. +/s/ GRANT THORNTON LLP +Dallas, Texas +March 17, 2014 +F- 3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2014 +2013 +ASSETS +Current assets +Cash +$ +8,407 +$ +6,287 +Restricted cash +609 +— +Accounts receivable +Oil and natural gas revenues +28,976 +25,823 +Joint interest billings +6,925 +4,785 +Other +9,091 +1,066 +Derivative instruments +55,549 +19 +Deferred income taxes +— +1,636 +Lease and well equipment inventory +1,212 +785 +Prepaid expenses and other assets +2,554 +2,474 +Total current assets +113,323 +42,875 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +1,617,913 +1,090,656 +Unproved and unevaluated +264,419 +194,306 +Other property and equipment +43,472 +29,910 +Less accumulated depletion, depreciation and amortization +(603,732 +) +(468,995 +) +Net property and equipment +1,322,072 +845,877 +Other assets +Derivative instruments +— +173 +Other assets +896 +1,405 +Total other assets +896 +1,578 +Total assets +$ +1,436,291 +$ +890,330 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +17,526 +$ +25,358 +Accrued liabilities +109,502 +63,987 +Royalties payable +14,461 +7,798 +Derivative instruments +— +2,692 +Deferred income taxes +19,751 +— +Income taxes payable +444 +404 +Other current liabilities +103 +88 +Total current liabilities +161,787 +100,327 +Long-term liabilities +Borrowings under Credit Agreement +340,000 +200,000 +Asset retirement obligations +11,640 +7,309 +Derivative instruments +— +253 +Deferred income taxes +53,783 +10,929 +Other long-term liabilities +2,540 +2,588 +Total long-term liabilities +407,963 +221,079 +Commitments and contingencies (Note 13) +Shareholders’ equity +Common stock — Class A, $0.01 par value, 80,000,000 shares authorized; 73,373,744 and 66,958,867 shares issued; 73,342,777 and 65,652,690, shares outstanding, respectively +734 +670 +Additional paid-in capital +724,819 +548,935 +Retained earnings +140,855 +30,084 +Treasury stock, at cost, 30,967 and 1,306,177 shares, respectively +— +(10,765 +) +Total Matador Resources Company shareholders' equity +866,408 +568,924 +Non-controlling interest in subsidiary +133 +— +Total shareholders' equity +866,541 +568,924 +Total liabilities and shareholders’ equity +$ +1,436,291 +$ +890,330 +The accompanying notes are an integral part of these financial statements. +F- 4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2014 +2013 +2012 +Revenues +Oil and natural gas revenues +$ +367,712 +$ +269,030 +$ +155,998 +Realized gain (loss) on derivatives +5,022 +(909 +) +13,960 +Unrealized gain (loss) on derivatives +58,302 +(7,232 +) +(4,802 +) +Total revenues +431,036 +260,889 +165,156 +Expenses +Production taxes and marketing +33,172 +20,973 +11,672 +Lease operating +51,353 +38,720 +28,184 +Depletion, depreciation and amortization +134,737 +98,395 +80,454 +Accretion of asset retirement obligations +504 +348 +256 +Full-cost ceiling impairment +— +21,229 +63,475 +General and administrative +32,152 +20,779 +14,543 +Total expenses +251,918 +200,444 +198,584 +Operating income (loss) +179,118 +60,445 +(33,428 +) +Other income (expense) +Net loss on asset sales and inventory impairment +— +(192 +) +(485 +) +Interest expense, net of amounts capitalized +(5,334 +) +(5,687 +) +(1,002 +) +Interest and other income +1,345 +225 +224 +Total other expense +(3,989 +) +(5,654 +) +(1,263 +) +Income (loss) before income taxes +175,129 +54,791 +(34,691 +) +Income tax provision (benefit) +Current +133 +404 +— +Deferred +64,242 +9,293 +(1,430 +) +Total income tax provision (benefit) +64,375 +9,697 +(1,430 +) +Net income (loss) +110,754 +45,094 +(33,261 +) +Net loss attributable to non-controlling interest in subsidiary +17 +— +— +Net income (loss) attributable to +Matador Resources Company shareholders +$ +110,771 +$ +45,094 +$ +(33,261 +) +Earnings (loss) per common share +Basic +Class A +$ +1.58 +$ +0.77 +$ +(0.62 +) +Class B +$ +— +$ +— +$ +(0.35 +) +Diluted +Class A +$ +1.56 +$ +0.77 +$ +(0.62 +) +Class B +$ +— +$ +— +$ +(0.35 +) +Weighted average common shares outstanding +Basic +Class A +70,229 +58,777 +53,852 +Class B +— +— +105 +Total +70,229 +58,777 +53,957 +Diluted +Class A +70,906 +58,929 +53,852 +Class B +— +— +105 +Total +70,906 +58,929 +53,957 +The accompanying notes are an integral part of these financial statements. +F- 5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +For the Years Ended December 31, 2014, 2013 and 2012 +(In thousands) +Total shareholders' equity attributable to Matador Resources Company +Common Stock +Additional +paid-in +capital +Retained earnings (deficit ) +Treasury Stock +Non-controlling interest in subsidiary +Total shareholders' equity +Class A +Class B +Shares +Amount +Shares +Amount +Shares +Amount +Balance at January 1, 2012 +42,917 +$ +429 +1,031 +$ +10 +$ +263,562 +$ +18,279 +1,179 +$ +(10,765 +) +$ +271,515 +$ +— +$ +271,515 +Issuance of Class A common stock +12,209 +122 +— +— +146,388 +— +— +— +146,510 +— +146,510 +Cost to issue equity +— +— +— +— +(11,268 +) +— +— +— +(11,268 +) +— +(11,268 +) +Conversion of Class B common stock to Class A common stock +1,031 +10 +(1,031 +) +(10 +) +— +— +— +— +— +— +— +Issuance of Class A common stock to Board members and advisors +7 +— +— +— +71 +— +— +— +71 +— +71 +Stock options expense related to equity-based awards +— +— +— +— +432 +— +— +— +432 +— +432 +Stock options exercised +296 +3 +— +— +3,541 +— +— +— +3,544 +— +3,544 +Liability-based stock option awards settled +— +— +— +— +216 +— +— +— +216 +— +216 +Changes in fair value for liability-based stock option awards for which grant date fair value is in excess of fair value +— +— +— +— +620 +— +— +— +620 +— +620 +Restricted stock issued +319 +4 +— +— +(4 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +(29 +) +— +22 +— +(29 +) +— +(29 +) +Restricted stock and restricted stock units expense +— +— +— +— +758 +— +— +— +758 +— +758 +Swing sale profit contribution +— +— +— +— +24 +— +— +— +24 +— +24 +Class B dividends declared +— +— +— +— +— +(28 +) +— +— +(28 +) +— +(28 +) +Current period net loss +— +— +— +— +— +(33,261 +) +— +— +(33,261 +) +— +(33,261 +) +Balance at December 31, 2012 +56,779 +568 +— +— +404,311 +(15,010 +) +1,201 +(10,765 +) +379,104 +— +379,104 +Issuance of common stock +9,780 +98 +— +— +148,971 +— +— +— +149,069 +— +149,069 +Cost to issue equity +— +— +— +— +(7,390 +) +— +— +— +(7,390 +) +— +(7,390 +) +Issuance of common stock to Board members and advisors +22 +— +— +— +57 +— +— +— +57 +— +57 +Stock options expense related to equity-based awards +— +— +— +— +1,232 +— +— +— +1,232 +— +1,232 +Liability-based stock option awards settled +— +— +— +— +162 +— +— +— +162 +— +162 +Restricted stock issued +378 +4 +— +— +(4 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +(22 +) +— +105 +— +(22 +) +— +(22 +) +Restricted stock and restricted stock units expense +— +— +— +— +1,618 +— +— +— +1,618 +— +1,618 +Current period net income +— +— +— +— +— +45,094 +— +— +45,094 +— +45,094 +Balance at December 31, 2013 +66,959 +670 +— +— +548,935 +30,084 +1,306 +(10,765 +) +568,924 +— +568,924 +Issuance of common stock +7,500 +75 +— +— +181,800 +— +— +— +181,875 +— +181,875 +Cost to issue equity +— +— +— +— +(590 +) +— +— +— +(590 +) +— +(590 +) +Common stock issued to Board members and advisors +30 +— +— +— +16 +— +— +— +16 +— +16 +Stock options expense related to equity-based awards +— +— +— +— +2,279 +— +— +— +2,279 +— +2,279 +Stock options exercised +8 +— +— +— +43 +— +— +— +43 +— +43 +Liability-based stock option awards settled +— +— +— +— +84 +— +— +— +84 +— +84 +Restricted stock issued +212 +2 +— +— +(2 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +(17 +) +— +60 +— +(17 +) +— +(17 +) +Restricted stock and restricted stock units expense +— +— +— +— +3,023 +— +— +— +3,023 +— +3,023 +Cancellation of treasury stock +(1,335 +) +(13 +) +— +— +(10,752 +) +— +(1,335 +) +10,765 +— +— +— +Capital contributed to less-than-wholly-owned subsidiary +— +— +— +— +— +— +— +— +— +150 +150 +Current period net income (loss) +— +— +— +— +— +110,771 +— +— +110,771 +(17 +) +110,754 +Balance at December 31, 2014 +73,374 +$ +734 +— +$ +— +$ +724,819 +$ +140,855 +31 +$ +— +$ +866,408 +$ +133 +$ +866,541 +The accompanying notes are an integral part of these financial statements. +F- 6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +2014 +2013 +2012 +Operating activities +Net income (loss) +$ +110,754 +$ +45,094 +$ +(33,261 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized (gain) loss on derivatives +(58,302 +) +7,232 +4,802 +Depletion, depreciation and amortization +134,737 +98,395 +80,454 +Accretion of asset retirement obligations +504 +348 +256 +Full-cost ceiling impairment +— +21,229 +63,475 +Stock-based compensation expense +5,524 +3,897 +140 +Deferred income tax provision (benefit) +64,242 +9,293 +(1,430 +) +Loss on asset sales and inventory impairment +— +192 +485 +Changes in operating assets and liabilities +Accounts receivable +(13,318 +) +(2,160 +) +(16,342 +) +Lease and well equipment inventory +(211 +) +243 +50 +Prepaid expenses +(783 +) +(668 +) +50 +Other assets +1,212 +(548 +) +(673 +) +Accounts payable, accrued liabilities and other current liabilities +607 +(3,638 +) +19,740 +Royalties payable +6,663 +1,257 +4,685 +Advances from joint interest owners +— +(1,515 +) +1,515 +Income taxes payable +39 +404 +— +Other long-term liabilities +(187 +) +415 +282 +Net cash provided by operating activities +251,481 +179,470 +124,228 +Investing activities +Proceeds from sale of oil and natural gas properties +79 +— +— +Oil and natural gas properties capital expenditures +(560,849 +) +(363,192 +) +(300,689 +) +Expenditures for other property and equipment +(9,152 +) +(3,977 +) +(7,332 +) +Purchases of certificates of deposit +— +(61 +) +(496 +) +Maturities of certificates of deposit +— +291 +1,601 +Restricted cash in less-than-wholly-owned subsidiary +(609 +) +— +— +Net cash used in investing activities +(570,531 +) +(366,939 +) +(306,916 +) +Financing activities +Repayments of borrowings under Credit Agreement +(180,000 +) +(130,000 +) +(123,000 +) +Borrowings under Credit Agreement +320,000 +180,000 +160,000 +Proceeds from issuance of common stock +181,875 +149,069 +146,510 +Swing sale profit contribution +— +— +24 +Cost to issue equity +(590 +) +(7,390 +) +(11,599 +) +Proceeds from stock options exercised +43 +— +2,660 +Capital commitment from non-controlling interest in subsidiary +150 +— +— +Taxes paid related to net share settlement of stock-based compensation +(308 +) +(18 +) +— +Payment of dividends — Class B +— +— +(96 +) +Net cash provided by financing activities +321,170 +191,661 +174,499 +Increase (decrease) in cash +2,120 +4,192 +(8,189 +) +Cash at beginning of year +6,287 +2,095 +10,284 +Cash at end of year +$ +8,407 +$ +6,287 +$ +2,095 +Supplemental disclosures of cash flow information (Note 14) +The accompanying notes are an integral part of these financial statements. +F- 7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2014, 2013 and 2012 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. The Company also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company proportionately consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. All significant intercompany balances and transactions have been eliminated in consolidation. +The Company’s operations are conducted in the one segment generally referred to as the oil and natural gas exploration and production industry. +Reclassifications +Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Restricted Cash +Restricted cash represents the cash held by our less-than-wholly-owned subsidiary. By contractual agreement, the cash in this account is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of this less-than-wholly-owned subsidiary, which disposes of limited quantities of Company and third-party salt water. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ — Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s +F- 8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future well operations or equipment held for sale. +Property and Equipment +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $6.4 million , $3.7 million and $2.6 million of its general and administrative costs in 2014 , 2013 and 2012 , respectively. The Company capitalized $2.8 million , $1.9 million and $1.6 million of its interest expense for the years ended December 31, 2014, 2013 and 2012 , respectively. +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling”. The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Since January 1, 2011, the need for a full-cost ceiling impairment is required to be assessed on a quarterly basis. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and the guidelines further dictate that a 10% discount factor be used to determine the present value of future net revenues. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per barrel and $4.350 per MMBtu, respectively. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.670 per MMBtu, respectively. For the period from January through December 2012 , these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average +F- 9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +Using these average commodity prices, as adjusted, to determine the Company’s estimated proved oil and natural gas reserves at each quarter end during the year ended December 31, 2014 , the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2014 . +At March 31, 2013, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . The Company recorded an impairment charge of $21.2 million to its net capitalized costs and a deferred income tax credit of $7.5 million related to the full-cost ceiling limitation. These charges are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2013. +At June 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . The Company recorded an impairment charge of $33.2 million to its net capitalized costs and a deferred income tax credit of $11.9 million related to the full-cost ceiling limitation. At September 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . The Company recorded an impairment charge of $3.6 million to its net capitalized costs and a deferred income tax credit of $1.3 million related to the full-cost ceiling limitation. At December 31, 2012, the Company’s net capitalized costs exceeded the full-cost center ceiling by $17.3 million . The Company recorded an impairment charge of $26.7 million to its net capitalized costs and a deferred income tax credit of $9.4 million related to the full-cost ceiling limitation. These charges for the second, third and fourth quarters of 2012 are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2012. +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Other property and equipment are recorded at historical cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life ( five to 10 years) using the straight-line method. Support equipment and facilities include the Company’s pipelines and salt water disposal systems and are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statement of operations. In general, the Company’s future asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, +F- 10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in its estimate or if federal or state regulators enact new plugging and abandonment requirements. At the time of actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent that the actual costs are different from the estimated liability. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide the Company with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. The Company’s derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations (see Note 11). The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statement of operations. +Revenue Recognition +The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. +For the year ended December 31, 2014 , the Company had three significant purchasers that accounted for approximately 68% of its total oil, natural gas and natural gas liquids revenues. For the year ended December 31, 2013 and 2012 , the Company had five and three significant purchasers that accounted for approximately 87% and 74% , respectively, of its total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2014, 2013 and 2012 , approximately 44% , 81% and 67% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Stock-Based Compensation +Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. During 2014 , 2013 and 2012 , all stock option awards granted under the 2012 Incentive Plan were non-qualified options and the associated compensation expense is recognized over the vesting period, which is typically three or four years. All stock option awards granted in 2014 , 2013 and 2012 are classified as equity instruments due to the methods of exercise specified in the 2012 Incentive Plan. Compensation expense for restricted stock and restricted stock unit grants awarded in 2014 , 2013 and 2012 was recognized immediately or over the vesting period, which is typically one to four years. +The Company did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under the 2003 Stock and Incentive Plan (the “2003 Plan”), and since November 22, 2010, these awards have been accounted for as liability instruments. No additional stock-based compensation will be awarded under the 2003 Plan. Non-qualified stock option grants awarded under the 2003 Plan typically vested upon issuance, while incentive stock option grants awarded under the 2003 Plan typically vested over four years, and the associated compensation expense was recognized on a straight-line basis over the vesting period. Compensation expense for restricted stock grants awarded under the 2003 Plan was recognized immediately or over the vesting period, which was typically three years. +F- 11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +At December 31, 2014, 2013 and 2012 , the Company used the fair value method to measure and recognize the liability and equity associated with its outstanding stock options. +Prior to November 22, 2010, all of the Company’s then-outstanding stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, the Company changed its method of accounting for its then-outstanding stock options, reclassifying all of its then-outstanding stock options from equity to liability instruments. This change was made as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s Class A common stock. At December 31, 2014 , the Company continued to account for all outstanding stock options granted under the 2003 Plan as liability instruments. +The Company’s consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 include a stock-based compensation (non-cash) expense of $5.5 million , $3.9 million and $0.1 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.3 million , $0.3 million and $0.1 million in 2014 , 2013 and 2012 , respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and provides a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. Management believes that the material positions taken by the Company would more likely than not be sustained by examination. At December 31, 2014 and 2013 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income tax for the years ended December 31, 2014, 2013 and 2012 . +Earnings Per Common Share +The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +Prior to consummation of the Company’s initial public offering (the “Initial Public Offering”) (see Note 10) in February 2012, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during 2012 totaled $27,643 . Class B dividends declared during the fourth quarter of 2011 and the first quarter of 2012 were paid during the first quarter of 2012 totaling $96,356 . As of December 31, 2014 , the Company has not paid any dividends to holders of the Class A shares. Concurrent with the completion of the Initial Public Offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. The Class A common stock is now referred to as the “common stock.” +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted distributed and undistributed earnings per common share as reported for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share data). +F- 12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Year Ended December 31, +2014 +2013 +2012 +Net income (loss) attributable to Matador Resources Company shareholders — numerator +Net income (loss) attributable to Matador Resources Company shareholders +$ +110,771 +$ +45,094 +$ +(33,261 +) +Less dividends to Class B shareholders — distributed earnings +— +— +(28 +) +Undistributed earnings (loss) +$ +110,771 +$ +45,094 +$ +(33,289 +) +Weighted average common shares outstanding — denominator +Basic +Class A +70,229 +58,777 +53,852 +Class B +— +— +105 +Total +70,229 +58,777 +53,957 +Diluted +Class A +Weighted average common shares outstanding for basic earnings (loss) per share +70,229 +58,777 +53,852 +Dilutive effect of options and restricted stock units +677 +152 +— +Class A weighted average common shares outstanding — diluted +70,906 +58,929 +53,852 +Class B +Weighted average common shares outstanding — no associated dilutive shares +— +— +105 +Total diluted weighted average common shares outstanding +70,906 +58,929 +53,957 +Year Ended December 31, +2014 +2013 +2012 +Earnings (loss) per common share attributable to +Matador Resources Company shareholders +Basic +Class A +Distributed earnings +$ +— +$ +— +$ +— +Undistributed earnings (loss) +$ +1.58 +$ +0.77 +$ +(0.62 +) +Total +$ +1.58 +$ +0.77 +$ +(0.62 +) +Class B +Distributed earnings +$ +— +$ +— +$ +0.27 +Undistributed earnings (loss) +$ +— +$ +— +$ +(0.62 +) +Total +$ +— +$ +— +$ +(0.35 +) +Diluted +Class A +Distributed earnings +$ +— +$ +— +$ +— +Undistributed earnings (loss) +$ +1.56 +$ +0.77 +$ +(0.62 +) +Total +$ +1.56 +$ +0.77 +$ +(0.62 +) +Class B +Distributed earnings +$ +— +$ +— +$ +0.27 +Undistributed earnings (loss) +$ +— +$ +— +$ +(0.62 +) +Total +$ +— +$ +— +$ +(0.35 +) +A total of 1,067,069 options to purchase shares of the Company’s Class A common stock and 162,368 restricted stock units were excluded from the calculations above for the year ended December 31, 2012 because their effects were anti-dilutive. +F- 13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Additionally, 305,807 restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2012 as the security holders do not have the obligation to share in the losses of the Company. +Fair Value Measurements +The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company follows Financial Accounting Standards Board (“FASB”) guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company believes that any credit risk posed is insignificant and is offset by the creditworthiness of its customer base and industry partners. +Recent Accounting Pronouncements +Revenue from Contracts with Customers. In May 2014, the FASB issued Accounting Standards Update, or ASU, 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. ASU 2014-09 will become effective for fiscal years beginning after December 15, 2016, i.e., in the Company’s first fiscal quarter of 2017. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements. +F- 14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2014 and 2013 (in thousands). +December 31, +2014 +2013 +Oil and natural gas properties +Evaluated (subject to amortization) +$ +1,617,913 +$ +1,090,656 +Unproved and unevaluated (not subject to amortization) +Incurred in 2014 +116,821 +— +Incurred in 2013 +62,332 +82,628 +Incurred in 2012 +12,891 +23,341 +Incurred in 2011 and prior +72,375 +88,337 +Total unproved and unevaluated +264,419 +194,306 +Total oil and natural gas properties +1,882,332 +1,284,962 +Accumulated depletion +(596,218 +) +(463,091 +) +Net oil and natural gas properties +1,286,114 +821,871 +Other property and equipment +Computer equipment +1,110 +1,044 +Furniture +1,191 +1,057 +Software +1,733 +1,456 +Other equipment +332 +252 +Leasehold improvements +971 +991 +Support equipment and facilities +38,135 +25,110 +Total other property and equipment +43,472 +29,910 +Accumulated depreciation +(7,514 +) +(5,904 +) +Net other property and equipment +35,958 +24,006 +Net property and equipment +$ +1,322,072 +$ +845,877 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2014 and the year in which these costs were incurred (in thousands). +Description +2014 +2013 +2012 +2011 and +prior +Total +Costs incurred for +Property acquisition +$ +87,207 +$ +62,332 +$ +12,800 +$ +72,375 +$ +234,714 +Exploration wells +21,494 +— +— +— +21,494 +Development wells +8,120 +— +— +— +8,120 +Capitalized interest +— +— +91 +— +91 +Total +$ +116,821 +$ +62,332 +$ +12,891 +$ +72,375 +$ +264,419 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred in 2014 were related primarily to the Company’s leasehold acquisitions in the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, but also include costs associated with additional leasehold acquisitions in the Eagle Ford shale play in South Texas. +F- 15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Property acquisition costs incurred in 2013 were related primarily to the Company’s leasehold acquisitions in the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, but also include costs associated with additional leasehold acquisitions in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana and East Texas. +Property acquisition costs incurred in 2012 were related primarily to the Company’s leasehold acquisitions in the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. +Property acquisition costs incurred in 2011 and prior years were related primarily to the Company’s leasehold acquisitions in the Eagle Ford shale play in South Texas and in the Haynesville shale play in Northwest Louisiana. These costs are associated with acreage for which proved reserves have yet to be assigned. Almost all of these costs are associated with properties which are held by production and have no near-term expiration risk. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base should be completed within three to five years or less. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $29.6 million for 2014 . Of this total, $21.5 million was associated with exploration wells and $8.1 million was associated with development wells. The Company anticipates that the entire $29.6 million associated with these wells in progress at December 31, 2014 will be transferred to the amortization base during 2015 . +NOTE 4 — ASSET RETIREMENT OBLIGATIONS +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2014 and 2013 (in thousands). +Year Ended December 31, +2014 +2013 +Beginning asset retirement obligations +$ +7,484 +$ +5,769 +Liabilities incurred during period +2,322 +936 +Liabilities settled during period +(22 +) +(103 +) +Revisions in estimated cash flows +1,663 +534 +Accretion expense +504 +348 +Ending asset retirement obligations +11,951 +7,484 +Less: current asset retirement obligations (1) +(311 +) +(175 +) +Long-term asset retirement obligations +$ +11,640 +$ +7,309 +__________________ +(1) +Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2014 and 2013 . +F- 16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 5 — ASSET SALES AND IMPAIRMENT +The Company recorded no impairment to any of its equipment held in inventory and realized no gain or loss on the sale of any of its inventory during the year ended December 31, 2014 . +In March 2013, the Company recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of pipe, was less than the cost. The carrying value was reduced by $0.2 million on the consolidated balance sheet, and a corresponding charge was recorded to the consolidated statement of operations for the year ended December 31, 2013 . +In December 2012, the Company recorded an impairment to reduce the remaining balance of its drilling rig parts held in inventory to zero following a determination that there was no current market for these parts. The carrying value of the inventory was reduced to zero and a charge of $0.4 million was recorded to the consolidated statement of operations. In addition, the Company recorded a loss of approximately $0.1 million on certain other equipment that was sold during 2012. +NOTE 6 — REVOLVING CREDIT AGREEMENT +On September 28, 2012 , the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million . The Credit Agreement matures December 29, 2016 . MRC Energy Company, which is a subsidiary of the Company and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of the Company’s proved oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2014 , the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2013 , and on March 12, 2014 , the borrowing base was increased to $385.0 million and the conforming borrowing base was increased to $310.0 million . At that time, Wells Fargo Bank, N.A. replaced Capital One, N.A., in the Company’s lending group, and the Company amended the Credit Agreement to, among other things, provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by the Company of senior unsecured notes in an amount greater than or equal to $10.0 million . The Credit Agreement was also amended to eliminate the current ratio covenant and to increase the debt to EBITDA ratio covenant, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, to 4.25 or less. Furthermore, the interest rate charged to the Company based on its outstanding level of borrowings was reduced by 0.25% across the borrowing grid as a result of this amendment. This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. +During the second quarter of 2014, Bank of America, N.A. replaced Citibank, N.A. as a lender under the Credit Agreement. +During the third quarter of 2014, the lenders completed their review of the Company’s estimated total proved oil and natural gas reserves at July 31, 2014, and as a result, on September 5, 2014, the borrowing base under the Credit Agreement was increased to $450.0 million , and the conforming borrowing base was increased to $375.0 million . This September 2014 borrowing base redetermination constituted the regularly scheduled November 1 redetermination. The Company may request one additional unscheduled redetermination of its borrowing base prior to the next scheduled redetermination. +At February 27, 2015 , the lenders had begun the regularly scheduled May 1 redetermination of the Company’s borrowing base using the Company’s estimated total proved oil and natural gas reserves at December 31, 2014 . Oil and natural gas prices have declined significantly in the six months since the September 2014 borrowing base redetermination. As a result, the Company cannot be certain as to how much, if any, its borrowing base may increase as a result of this May 1 redetermination. +In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. Total deferred loan costs were $1.8 million at December 31, 2014 , and these costs are being amortized over the term of the Credit +F- 17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued +Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +On May 29, 2014 , using a portion of the net proceeds from the Company’s public equity offering, the Company repaid $180.0 million of its outstanding borrowings under the Credit Agreement. At December 31, 2014 , the Company had $340.0 million in borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. At December 31, 2014 , the Company’s outstanding borrowings bore interest at an effective interest rate of approximately 3.3% per annum. From January 1, 2015 through February 27, 2015 , the Company borrowed an additional $55.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures, acquire additional leasehold interests and to consummate the HEYCO Merger. At February 27, 2015 , the Company had $395.0 million in borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. +If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 3.75% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50% , depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of the Company’s assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; and +• +engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving the Company or its subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +F- 18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued +At December 31, 2014 , the Company believes that it was in compliance with the terms of its Credit Agreement. +F- 19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 7 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2014 and 2013 , respectively, is as follows (in thousands). +December 31, +2014 +2013 +Current deferred tax assets +Property and equipment +$ +113 +$ +62 +Unrealized loss on derivatives +— +965 +Other +281 +609 +Total current deferred tax assets +394 +1,636 +Current deferred tax liabilities +Unrealized gain on derivatives +(20,145 +) +— +Net current deferred tax (liabilities) assets +$ +(19,751 +) +$ +1,636 +Non-current deferred tax assets +Unrealized loss on derivatives +$ +— +$ +28 +Net operating loss carryforwards +88,447 +63,007 +Alternative minimum tax carryforward +7,197 +7,064 +Percentage depletion carryover +2,068 +— +Total non-current deferred tax assets +97,712 +70,099 +Valuation allowance on non-current deferred tax assets +— +(30 +) +Total non-current deferred tax assets, net of valuation allowance +97,712 +70,069 +Non-current deferred tax liabilities +Property and equipment +(145,620 +) +(76,719 +) +Other +(5,875 +) +(4,279 +) +Total non-current deferred tax liabilities +(151,495 +) +(80,998 +) +Net non-current deferred tax liabilities +$ +(53,783 +) +$ +(10,929 +) +The Company had an effective tax rate of 36.8% for the year ended December 31, 2014 . Total income tax expense for the year ended December 31, 2014 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to the impact of state income taxes. The Company had an effective tax rate of 17.7% for the year ended December 31, 2013 due primarily to (i) the reversal of a valuation allowance of approximately $8.9 million on the Company’s federal deferred tax assets at December 31, 2013 , as the Company’s federal deferred tax liabilities exceeded its federal deferred tax assets for the year ended December 31, 2013 , (ii) the reversal of a state valuation allowance of approximately $1.3 million as the Company believed it would be able to utilize the state net operating losses prior to their expiration and (iii) the impact of permanent differences between book and taxable income. The Company reported a net loss for the year ended December 31, 2012. +At December 31, 2014 , the Company had net operating loss carryforwards of $242.0 million for federal income tax purposes and $3.8 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the state of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . +No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the year ended December 31, 2014 . +At March 31, 2013, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . As a result, the Company recorded an impairment charge of $21.2 million to its net capitalized costs and a deferred income tax credit of $7.5 million for the three months ended March 31, 2013. The Company established a valuation allowance at September 30, 2012 and retained full valuation allowances of approximately +F- 20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 7 — INCOME TAXES — Continued +$15.8 million at March 31, 2013 and $6.7 million at June 30, 2013 due to uncertainties regarding the future realization of the net deferred tax assets. +At June 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . As a result, the Company recorded an impairment charge of $33.2 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $11.9 million . At September 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . As a result, the Company recorded an impairment charge of $3.6 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $1.3 million . This deferred income tax credit exceeded the Company’s deferred tax liabilities at September 30, 2012. As a result, the Company established a valuation allowance of $2.4 million at September 30, 2012 due to uncertainties regarding the future realization of its deferred tax assets. At December 31, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million . As a result, the Company recorded an impairment charge of $26.7 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $9.4 million . This deferred income tax credit exceeded the Company’s deferred tax liabilities at December 31, 2012. As a result, the Company increased the previously established valuation allowance by $7.9 million to maintain a full valuation allowance of $10.3 million against the Company’s net deferred tax assets. +The income tax expense reconciled to the tax computed at the statutory federal rate for the years ended December 31, 2014, 2013 and 2012 , respectively, is as follows (in thousands). +Year Ended December 31, +2014 +2013 +2012 +Current income tax provision (benefit) +Federal alternative minimum tax +$ +133 +$ +404 +$ +— +Net current income tax provision +133 +404 +— +Deferred income tax provision (benefit) +Federal tax expense at statutory rate (1) +61,301 +19,177 +(11,767 +) +State income tax +2,707 +431 +(819 +) +Nondeductible expense +— +— +(122 +) +Permanent differences (2) +397 +319 +1,018 +Federal alternative minimum tax +(133 +) +(404 +) +— +Change in federal valuation allowance +— +(8,885 +) +10,260 +Change in state valuation allowance +(30 +) +(1,345 +) +— +Net deferred income tax provision (benefit) +64,242 +9,293 +(1,430 +) +Total income tax provision (benefit) +$ +64,375 +$ +9,697 +$ +(1,430 +) +__________________ +(1) +The statutory federal tax rate was 35% for the years ended December 31, 2014 and 2013 and 34% for the year ended December 31, 2012 . +(2) +Amount is primarily attributable to stock-based compensation. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The tax years open for examination for the federal tax return are 2011 , 2012 , 2013 and 2014 . The tax years open for examination by the state of Texas are 2009, 2010 , 2011 , 2012 , 2013 and 2014 . The tax years open for examination by the state of New Mexico are 2011 , 2012 , 2013 and 2014 . The tax years open for examination by the state of Louisiana are 2011 , 2012 , 2013 and 2014 . As of December 31, 2014 , the Company’s 2009 and 2010 franchise tax returns are under examination by the state of Texas. This examination is in the preliminary stage and no additional income taxes or refunds of previous tax payments for these tax years have been recorded as a result of this examination at December 31, 2014 . +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2014 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +F- 21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 8 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Plan. The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of Class A common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. +Effective January 1, 2012, the Board of Directors adopted the 2012 Incentive Plan. The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. The 2012 Incentive Plan provides for a maximum of 4,000,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. +The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which determines the number of options or restricted shares to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted during 2014, 2013 and 2012 were granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at every reporting period. +Stock Options +Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five or ten years. +The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2014, 2013 and 2012 . +2014 +2013 +2012 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +1.51 years +2.44 years +0.89 years +Risk-free interest rate +0.74% +0.69% +0.25% +Volatility +55.14% +51.51% +54.28% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +—% +0.79% +0.70% +The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2014 and 2013 . +2014 +2013 +2012 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +3.99 years +4.00 years +4.40 years +Risk-free interest rate +1.21% +0.69% +0.71% +Volatility +51.47% +58.65% +71.16% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +4.28% +6.37% +5.46% +Weighted average fair value of stock option awards granted during the year +$9.45 +$3.91 +$5.95 +F- 22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +The Company estimated the future volatility of its common stock using the historical value of its peer group for a period of time commensurate with the expected term of the stock option due to the lack of historical trading data available for its common stock. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2014 under the Company’s 2003 Plan and the 2012 Incentive Plan is as follows (in thousands, except price data). +Number of +options +Weighted +average +exercise price +Options outstanding at December 31, 2013 +1,428 +$ +9.32 +Options granted +419 +23.19 +Options exercised +(10 +) +8.95 +Options forfeited +(39 +) +13.21 +Options outstanding at December 31, 2014 +1,798 +$ +12.47 +Options outstanding at +December 31, 2014 +Options exercisable at +December 31, 2014 +Range of exercise prices +Shares +outstanding +Weighted +average +remaining +contractual +life +Weighted +average +exercise +price +Shares +exercisable +Weighted +average +exercise +price +$8.18 - $9.90 +919 +3.32 +$ +8.33 +105 +$ +8.96 +$10.39 - $17.80 +438 +2.51 +$ +10.65 +224 +$ +10.53 +$18.77 - $22.66 +165 +4.21 +$ +21.07 +— +$ +— +$23.40 - $27.58 +276 +4.19 +$ +24.02 +— +$ +— +At December 31, 2014 , the aggregate intrinsic value was $13.9 million for outstanding options and $3.3 million for exercisable options, based on the Company’s quoted closing market price of $20.23 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2014 was 3.38 years. +The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $0.2 million , $36,000 and $0.9 million , respectively. The tax related benefit realized from the exercise of stock options totaled $0.1 million , zero and zero for the years ended December 31, 2014, 2013 and 2012 , respectively. +During the years ended December 31, 2014, 2013 and 2012 , the Company recognized $2.5 million , $2.2 million and $(0.7) million , respectively, in stock-based compensation expense attributable to stock options. At December 31, 2014, 2013 and 2012 , the Company had recorded $1.4 million , $1.2 million and $0.3 million of long-term liabilities and zero , $0.1 million and $0.1 million of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2014, 2013 and 2012 , respectively. +At December 31, 2014 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $5.9 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.48 years. +The fair value of options vested during 2014 , 2013 and 2012 was $1.5 million , $0.3 million and $0.3 million , respectively. +Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes +F- 23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +an election to defer issuance for a term no longer than two years after vesting. No such elections were made with respect to the 2012 restricted stock unit awards; one current director elected to defer the issuance of his awards in 2014 and 2013. All awards granted in 2014 and 2013 were service based awards and vest over the service period which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2014 were granted under the 2012 Incentive Plan. +The 2012 restricted stock awards included 116,841 shares of performance based restricted stock and 116,841 performance based restricted stock units with a combined weighted average fair value of $13.24 per combined share and unit. These awards vest based on the outcome of the Company’s total shareholder return over a three -year period beginning March 19, 2012 and ending April 15, 2015 as compared to a designated peer group. These awards may result in the vesting of an aggregate of up to 116,841 restricted stock units in addition to the 116,841 shares of restricted stock. If the performance conditions are not met, however, these awards may result in no performance based restricted stock vesting and no restricted stock units vesting. The fair value of these awards was estimated based on the most likely outcome of the award as determined by the Monte Carlo method. A total of 206,842 service based restricted stock awards were granted during the year ended December 31, 2012, with a weighted average fair value of $9.66 per share. Of these awards, 13,833 shares of restricted stock vested immediately upon grant, and the remaining restricted stock vests over the service period, which ranges from one year to a maximum of four years . A total of 54,166 service based restricted stock unit awards were granted during the year ended December 31, 2012, with a weighted average fair value of $10.04 per unit. +A summary of the non-vested restricted stock and restricted stock units as of December 31, 2014 is presented below (in thousands, except fair value). +Restricted Stock +Restricted Stock Units +Service Based +Performance Based +Service Based +Performance Based +Non-vested restricted stock and +restricted stock units +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value (1) +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value (1) +Non-vested at +December 31, 2013 +464 +$ +9.43 +100 +$ +13.24 +86 +$ +10.79 +100 +$ +— +Granted +212 +23.30 +— +— +28 +25.36 +— +— +Vested +(51 +) +10.43 +— +— +(31 +) +10.61 +— +— +Forfeited +(56 +) +14.29 +(3 +) +13.24 +(12 +) +12.96 +(3 +) +— +Non-vested at +December 31, 2014 +569 +$ +14.03 +97 +$ +13.24 +71 +$ +16.28 +97 +$ +— +__________________ +(1) +The fair value of these restricted stock units is reflected in the fair value of the performance based restricted stock, which was estimated based on the most likely outcome of the award as determined by the Monte Carlo method. +At December 31, 2014 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $16.9 million as calculated based on the maximum number of shares of restricted stock, performance based restricted stock and restricted stock units vesting, using the stock price on December 31, 2014 . +During the years ended December 31, 2014, 2013 and 2012 , the Company recognized approximately $3.0 million , $1.6 million and $0.7 million , respectively, in stock-based compensation expense attributable to restricted stock and restricted stock units. +At December 31, 2014 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $6.9 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.23 years. +The fair value of restricted stock and restricted stock units vested during 2014 , 2013 and 2012 was $0.9 million , $0.2 million and $44,000 , respectively. +The total tax benefit recognized for all stock-based compensation was $1.9 million , $1.1 million and $0.3 million for the years ended December 31, 2014, 2013 and 2012 , respectively. +During the years ended December 31, 2014, 2013 and 2012 , the Company issued shares of common stock to certain members of its Board of Directors. The Company also issued shares of common stock to certain outside advisors who do not +F- 24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +meet the definition of employees under ASC 718. The Company used the fair value of the stock issued on the grant date to recognize the expense related to these awards. The Company recognized $16,000 , $0.1 million and $0.1 million in stock-based compensation expense attributable to these awards for the years ended December 31, 2014, 2013 and 2012 , respectively. +NOTE 9 — EMPLOYEE BENEFIT PLANS +401(k) Plan +Effective July 3, 2003, the Company established a defined contribution retirement plan. All full-time Company employees are eligible to join the plan the first day of the calendar month immediately following their date of employment. Each Participant may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution. The Company’s Safe Harbor match was approximately $0.4 million , $0.2 million and $0.2 million in 2014 , 2013 and 2012 , respectively. In addition, each year, the Company may make a discretionary matching contribution as well as additional contributions. The Company’s discretionary matching contributions totaled $0.5 million , $0.3 million and $0.3 million in 2014 , 2013 and 2012 , respectively. The Company made no additional discretionary contributions in any reporting period presented. +NOTE 10 — COMMON STOCK +Dividends +At December 31, 2011, the Company had issued two classes of common stock, Class A and Class B. In February 2012, upon the consummation of the Company’s Initial Public Offering, the Class B shares were converted to Class A shares, which are now referred to as common stock. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26 -2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared and paid during 2012 were $27,643 . Dividends for the fourth quarter of 2011 totaling $68,713 were accrued and paid in January 2012. As of December 31, 2014 , the Company has not paid any dividends to holders of the Class A shares. In addition, certain covenants in the Company’s Credit Agreement may limit the Company’s ability to pay dividends on its common stock. +Stock Offerings, Retirement and Issuances +On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting direct offering costs totaling approximately $0.6 million , the Company received net proceeds of approximately $181.3 million . The Company used a portion of the net proceeds to repay $180.0 million in outstanding borrowings under its Credit Agreement, which amounts were subsequently reborrowed in accordance with the terms of that facility. The remaining $1.3 million of the offering net proceeds was used to fund working capital requirements. +On September 10, 2013, the Company completed an underwritten public offering of 9,775,000 shares of its common stock, including 1,275,000 shares issued pursuant to the underwriters’ exercise of their option to purchase additional shares. After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million , the Company received net proceeds of approximately $141.7 million . The Company used the net proceeds from this offering primarily to fund a portion of its capital expenditures, including for the addition of the third rig to its drilling program. The Company also used the net proceeds from this offering to fund the acquisition of additional acreage in the Permian Basin, the Eagle Ford shale and the Haynesville shale. Pending such uses, the Company used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under its Credit Agreement in September 2013, which amounts were subsequently reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. The remaining $11.7 million of the offering net proceeds was used to fund working capital requirements. +On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the Initial Public Offering. The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC; Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc. and Comerica Securities, Inc. +On February 2, 2012, shares of the Company’s common stock began trading on the New York Stock Exchange under the symbol “MTDR” at an initial offering price of $12.00 per share. +F- 25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 10 — COMMON STOCK — Continued +Pursuant to its prospectus dated February 1, 2012 , the Company offered 11,666,667 shares of its common stock for sale, and the selling shareholders offered 1,550,000 shares for sale. On February 7, 2012 , the Company closed the Initial Public Offering and issued 11,666,667 shares of its common stock pursuant to the Initial Public Offering. +The Company and the selling shareholders granted the underwriters the right to purchase up to an additional 2,000,000 shares of the Company’s common stock at the initial offering price of $12.00 per share, less the underwriters’ discounts and commissions, for a period of 30 days following the Initial Public Offering to cover over-allotments, with the Company offering 700,000 shares and the selling shareholders offering 1,300,000 shares. On March 2, 2012, the underwriters exercised their option to purchase an additional 1,550,000 shares, including the purchase of 542,500 shares from the Company and the purchase of 1,007,500 shares from the selling shareholders. On March 7, 2012 , the Company closed this transaction and issued 542,500 shares of its common stock pursuant to the underwriters’ exercise of the over-allotment. +Pursuant to the Initial Public Offering and the over-allotment, the Company issued a total of 12,209,167 shares of its common stock at $12.00 per share and received estimated net proceeds of approximately $133.6 million after deducting the underwriters’ discounts and commissions and the estimated legal, accounting and other fees associated with the offering. The Company did not receive any proceeds from the sale of shares of its common stock by the selling shareholders. On February 8, 2012, the Company used the net proceeds of the offering to repay the $123.0 million in borrowings then outstanding under its Credit Agreement in full. The Company used the remaining net proceeds of the offering to fund a portion of its 2012 capital expenditures. +Concurrent with the completion of the Initial Public Offering, all 1,030,700 outstanding shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. In addition, in February 2012, the Company issued an additional 295,500 shares of its Class A common stock pursuant to the exercise of stock options and received net proceeds of $2.7 million . The Class A common stock is now referred to as the common stock. +Treasury Stock +On October 31, 2014, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2014. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +All 30,967 shares of treasury stock outstanding at December 31, 2014 and the increase of 105,126 shares in treasury stock outstanding during the year ended December 31, 2013 , represent forfeitures of non-vested restricted stock awards. +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless collars and swap contracts. The Company records derivative financial instruments on its consolidated balance sheet as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. RBC, Comerica Bank, The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for all of the Company’s commodity derivatives at December 31, 2014 . The Company has evaluated and considered the credit standings of the counterparties in determining the fair value of its derivative financial instruments. +The Company has entered into various costless collar contracts to mitigate its exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to +F- 26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. +The Company has entered into various costless collar transactions for natural gas, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to the Company pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. +The Company has entered into various swap contracts to mitigate its exposure to fluctuations in natural gas liquids (“NGL”) prices, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to the Company pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET prop” on the pricing date. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. +At December 31, 2014 , the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2015. +At December 31, 2014 , the Company had various swap contracts open and in place to mitigate its exposure to NGL price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and fixed price. Each contract is set to expire at varying times during 2015. +F- 27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following is a summary of the Company’s open costless collar contracts for oil and natural gas and open swap contracts for NGL at December 31, 2014 . +Notional Quantity (Bbl/month) +Price Floor ($/Bbl) +Price Ceiling ($/Bbl) +Fair Value of Asset (thousands) +Commodity +Calculation Period +Oil +01/01/2015 - 12/31/2015 +20,000 +$ +80.00 +$ +100.00 +$ +5,757 +Oil +01/01/2015 - 12/31/2015 +20,000 +80.00 +101.00 +5,770 +Oil +01/01/2015 - 12/31/2015 +20,000 +83.00 +96.12 +6,408 +Oil +01/01/2015 - 12/31/2015 +20,000 +83.00 +97.00 +6,407 +Oil +01/01/2015 - 12/31/2015 +20,000 +85.00 +99.00 +6,874 +Oil +01/01/2015 - 12/31/2015 +20,000 +85.00 +100.00 +6,873 +Oil +01/01/2015 - 12/31/2015 +20,000 +85.00 +105.10 +6,890 +Total open oil costless collar contracts +44,979 +Notional Quantity (MMBtu/month) +Price Floor ($/MMBtu) +Price Ceiling ($/MMBtu) +Fair Value of Asset (thousands) +Commodity +Calculation Period +Natural Gas +01/01/2015 - 03/31/2015 +200,000 +4.00 +4.84 +613 +Natural Gas +01/01/2015 - 03/31/2015 +300,000 +4.00 +4.93 +920 +Natural Gas +01/01/2015 - 03/31/2015 +150,000 +4.00 +5.25 +457 +Natural Gas +01/01/2015 - 12/31/2015 +100,000 +3.75 +4.36 +932 +Natural Gas +01/01/2015 - 12/31/2015 +100,000 +3.75 +4.45 +938 +Natural Gas +01/01/2015 - 12/31/2015 +100,000 +3.75 +4.60 +945 +Natural Gas +01/01/2015 - 12/31/2015 +100,000 +3.75 +4.65 +963 +Natural Gas +01/01/2015 - 12/31/2015 +200,000 +3.75 +5.04 +1,911 +Natural Gas +01/01/2015 - 12/31/2015 +100,000 +3.75 +5.34 +963 +Total open natural gas costless collar contracts +8,642 +Notional Quantity (Gal/month) +Fixed Price ($/Gal) +Fair Value of Asset (thousands) +Commodity +Calculation Period +Propane +01/01/2015 - 12/31/2015 +150,000 +1.000 +865 +Propane +01/01/2015 - 12/31/2015 +100,000 +1.030 +612 +Propane +01/01/2015 - 12/31/2015 +68,000 +1.073 +451 +Total open NGL swap contracts +1,928 +Total open derivative financial instruments +$ +55,549 +These derivative financial instruments are subject to master netting arrangements within specific commodity types, i.e., oil, natural gas and NGL, by counterparty. Derivative financial instruments with Counterparty A are not subject to master netting across commodity types, while derivative financial instruments with Counterparties B, C and D allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheet. +F- 28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2014 (in thousands). +Derivative Instruments +Gross +amounts of +recognized +assets +Gross amounts +netted in the +consolidated +balance sheet +Net amounts of +assets +presented in the +consolidated +balance sheet +Amounts subject to master netting arrangements presented on a gross basis +Counterparty A +Current assets +$ +13,437 +$ +(157 +) +$ +13,280 +$ +— +Other assets +— +— +— +— +Counterparty B +Current assets +8,759 +(116 +) +8,643 +— +Other assets +— +— +— +— +Counterparty C +Current assets +25,685 +(368 +) +25,317 +— +Other assets +— +— +— +— +Counterparty D +Current assets +8,374 +(65 +) +8,309 +— +Other assets +— +— +— +— +Total +$ +56,255 +$ +(706 +) +$ +55,549 +$ +— +The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2014 (in thousands). +Derivative Instruments +Gross +amounts of +recognized +liabilities +Gross amounts +netted in the +consolidated +balance sheet +Net amounts of +liabilities +presented in the +consolidated +balance sheet +Amounts subject to master netting arrangements presented on a gross basis +Counterparty A +Current liabilities +$ +157 +$ +(157 +) +$ +— +$ +— +Long-term liabilities +— +— +— +— +Counterparty B +Current liabilities +116 +(116 +) +— +— +Long-term liabilities +— +— +— +— +Counterparty C +Current liabilities +368 +(368 +) +— +— +Long-term liabilities +— +— +— +— +Counterparty D +Current liabilities +65 +(65 +) +— +— +Long-term liabilities +— +— +— +— +Total +$ +706 +$ +(706 +) +$ +— +$ +— +F- 29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2013 (in thousands). +Derivative Instruments +Gross +amounts of +recognized +assets +Gross amounts +netted in the +consolidated +balance sheet +Net amounts of +assets +presented in the +consolidated +balance sheet +Amounts subject to master netting arrangements presented on a gross basis +Counterparty A +Current assets +$ +1,746 +$ +(1,746 +) +$ +— +$ +— +Other assets +— +— +— +— +Counterparty B +Current assets +1,371 +(1,371 +) +— +— +Other assets +841 +(668 +) +173 +— +Counterparty C +Current assets +2,886 +(2,873 +) +13 +— +Other assets +1,046 +(1,046 +) +— +— +Counterparty D +Current assets +6 +— +6 +— +Other assets +— +— +— +— +Total +$ +7,896 +$ +(7,704 +) +$ +192 +$ +— +The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2013 (in thousands). +Derivative Instruments +Gross +amounts of +recognized +liabilities +Gross amounts +netted in the +consolidated +balance sheet +Net amounts of +liabilities +presented in the +consolidated +balance sheet +Amounts subject to master netting arrangements presented on a gross basis +Counterparty A +Current liabilities +$ +2,550 +$ +(1,746 +) +$ +804 +$ +— +Long-term liabilities +— +— +— +— +Counterparty B +Current liabilities +2,136 +(1,371 +) +765 +— +Long-term liabilities +668 +(668 +) +— +— +Counterparty C +Current liabilities +3,996 +(2,873 +) +1,123 +— +Long-term liabilities +1,299 +(1,046 +) +253 +— +Counterparty D +Current liabilities +— +— +— +— +Long-term liabilities +— +— +— +— +Total +$ +10,649 +$ +(7,704 +) +$ +2,945 +$ +— +F- 30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. +Location in +Year Ended December 31, +Type of Instrument +Statement of Operations +2014 +2013 +2012 +Derivative Instrument +Oil +Revenues: Realized gain (loss) on derivatives +$ +5,221 +$ +(2,408 +) +$ +2,047 +Natural Gas +Revenues: Realized (loss) gain on derivatives +(718 +) +831 +11,892 +NGL +Revenues: Realized gain on derivatives +519 +668 +21 +Realized gain (loss) on derivatives +5,022 +(909 +) +13,960 +Oil +Revenues: Unrealized gain (loss) on derivatives +47,178 +(5,319 +) +3,673 +Natural Gas +Revenues: Unrealized gain (loss) on derivatives +9,087 +(1,580 +) +(8,700 +) +NGL +Revenues: Unrealized gain (loss) on derivatives +2,037 +(333 +) +225 +Unrealized gain (loss) on derivatives +58,302 +(7,232 +) +(4,802 +) +Total +$ +63,324 +$ +(8,141 +) +$ +9,158 +F- 31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 12 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 +Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. +Level 2 +Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 +Unobservable inputs that are not corroborated by market data. This category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based on internally developed models or methodologies using significant inputs that are generally less readily observable from objective sources. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +At December 31, 2014 and 2013 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities. +At December 31, 2014 and 2013 , the carrying value of borrowings under the Credit Agreement approximates fair value as it is subject to short-term floating interest rates that reflect market rates available to the Company at the time and is classified at Level 2. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2014 and 2013 (in thousands). +Fair Value Measurements at +December 31, 2014 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil, natural gas and NGL derivatives +$ +— +$ +55,549 +$ +— +$ +55,549 +Total +$ +— +$ +55,549 +$ +— +$ +55,549 +Fair Value Measurements at +December 31, 2013 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil, natural gas and NGL derivatives +$ +— +$ +192 +$ +— +$ +192 +Oil, natural gas and NGL derivatives +— +(2,945 +) +— +(2,945 +) +Total +$ +— +$ +(2,753 +) +$ +— +$ +(2,753 +) +The Company’s accounting policies for financial instruments are discussed in Note 2; additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified at Level 2. +F- 32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 12 — FAIR VALUE MEASUREMENTS — Continued +The Company accounts for additions to asset retirement obligations and lease and well equipment inventory when adjusted for impairment at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis as of December 31, 2014 and 2013 (in thousands). +Fair Value Measurements at +December 31, 2014 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Asset retirement obligations +$ +— +$ +— +$ +(3,985 +) +$ +(3,985 +) +Total +$ +— +$ +— +$ +(3,985 +) +$ +(3,985 +) +Fair Value Measurements at +December 31, 2013 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Asset retirement obligations +$ +— +$ +— +$ +(1,470 +) +$ +(1,470 +) +Total +$ +— +$ +— +$ +(1,470 +) +$ +(1,470 +) +The Company’s accounting policies for asset retirement obligations are discussed in Note 2; reconciliations of the Company’s asset retirement obligations are provided in Note 4 for the periods presented. For purposes of fair value measurement, the Company determined that the additions to asset retirement obligations should be classified at Level 3. +The Company’s accounting policies for lease and well equipment inventory are discussed in Note 2. For purposes of fair value measurement, the Company determined that lease and well equipment inventory should be classified at Level 3. The Company recorded no impairment to its equipment, consisting primarily of pipe, held in inventory in 2014 . The Company recorded an impairment of $0.2 million to its equipment, consisting primarily of pipe, held in inventory in 2013 . +F- 33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 13 — COMMITMENTS AND CONTINGENCIES +Office Lease +The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. In April 2013 , the Company entered into the fifth amendment to its office lease agreement. This amendment increased the square footage of its corporate headquarters to 40,071 square feet effective July 1, 2013 . The lease expires on June 30, 2022 . +The effective base rent over the term of the lease extension is $20.28 per square foot per year. The base rate escalates several times during the course of the lease, specifically in July 2015, July 2017, July 2019 and July 2020; however, the Company recognizes rent expense ratably over the term of the lease. During the year ended December 31, 2014 , the Company also entered into a short-term lease for additional office space in its corporate headquarters; this lease expires in April 2015. +From time to time, the Company also enters into leases for field offices in locations where we have active field operations. These leases are typically for terms of less than five years and are not considered principal properties. None of the field office locations discussed above are considered principal properties. +The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2014 (in thousands). +Year Ending December 31, +Amount +2015 +$ +971 +2016 +885 +2017 +905 +2018 +927 +2019 +941 +Thereafter +2,418 +Total +$ +7,047 +Rent expense, including fees for operating expenses and consumption of electricity, was $0.9 million , $0.8 million and $0.6 million for 2014 , 2013 and 2012 , respectively. +Natural Gas and NGL Processing and Transportation Commitments +Effective September 1, 2012 , the Company entered into a firm five -year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid approximately $5.8 million and $5.3 million in processing and transportation fees under this agreement during the years ended December 31, 2014 and 2013 , respectively. +F- 34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued +The aggregate undiscounted minimum commitments under this agreement at December 31, 2014 are as follows (in thousands). +Year Ending December 31, +Amount +2015 +$ +2,992 +2016 +1,801 +2017 +1,195 +Total +$ +5,988 +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for one year or less, although in 2014, the Company entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were experiencing heavy demand for drilling rigs. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $50.4 million at December 31, 2014 . +The Company entered into an agreement with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in Loving County, Texas in 2014 . This plant is expected to process a portion of the Company’s natural gas produced from certain of its wells in the Permian Basin, as well as third-party natural gas once the plant is completed. Total commitments under this contract are $17.0 million and the Company had made payments totaling $2.1 million during the year ended December 31, 2014 . The plant is scheduled to be completed and placed in service in the third quarter of 2015. +At December 31, 2014 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $21.0 million at December 31, 2014 . The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a defendant in several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F- 35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 14 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2014 and 2013 (in thousands). +December 31, +2014 +2013 +Accrued evaluated and unproved and unevaluated property costs +$ +86,259 +$ +52,605 +Accrued support equipment and facilities costs +4,290 +— +Accrued stock-based compensation +— +56 +Accrued lease operating expenses +9,034 +6,251 +Accrued interest on borrowings under Credit Agreement +206 +141 +Accrued asset retirement obligations +311 +175 +Accrued partners’ share of joint interest charges +3,767 +1,173 +Other +5,635 +3,586 +Total accrued liabilities +$ +109,502 +$ +63,987 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2014, 2013 and 2012 (in thousands). +Year Ended December 31, +2014 +2013 +2012 +Cash paid for interest expense, net of amounts capitalized +$ +5,269 +$ +5,801 +$ +780 +Asset retirement obligations related to mineral properties +3,843 +1,363 +1,195 +Asset retirement obligations related to support equipment and facilities +120 +3 +49 +Increase in liabilities for oil and natural gas properties capital expenditures +32,972 +7,458 +24,847 +Increase in liabilities for support equipment and facilities +4,290 +660 +1,112 +Issuance of restricted stock units for Board and advisor services +444 +274 +73 +Issuance of common stock for Board and advisor services +16 +57 +71 +Decrease in liabilities for accrued cost to issue equity +— +— +(332 +) +Stock-based compensation expense recognized as liability +223 +1,012 +(1,092 +) +Transfer of inventory to oil and natural gas properties +216 +343 +69 +NOTE 15 — SUBSIDIARY GUARANTORS +Matador filed a registration statement on Form S-3 with the SEC in 2013, which became effective May 9, 2013, and a registration statement on Form S-3 with the SEC in 2014, which became effective upon filing on May 22, 2014, registering, in each case, among other securities, senior and subordinated debt securities. Certain subsidiaries of Matador (the “Guarantor Subsidiaries”) are co-registrants with Matador on each Form S-3, and the registration statements register guarantees of debt securities by the Guarantor Subsidiaries. As of December 31, 2014 , the Guarantor Subsidiaries are 100% owned by Matador, and any guarantees by the Guarantor Subsidiaries will be full and unconditional (except for customary release provisions). Matador had no significant assets or operations independent of the Guarantor Subsidiaries, and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to Matador. In the event that more than one of the Guarantor Subsidiaries provide guarantees of any debt securities issued by Matador, such guarantees will constitute joint and several obligations. As of December 31, 2014 , the Company had no outstanding debt securities. +NOTE 16 — SUBSEQUENT EVENTS +On February 27, 2015 , the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through which it obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico consisting of approximately 58,600 gross ( 18,200 net) +F- 36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2014, 2013 and 2012 +NOTE 16 — SUBSEQUENT EVENTS — Continued +acres (unaudited) located in Lea and Eddy Counties, New Mexico, strategically located between Matador’s existing acreage in its Ranger and Rustler Breaks prospect areas. HEYCO, headquartered in Roswell, New Mexico, was privately owned prior to the transaction. As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Preferred Stock). Matador paid an additional $3.0 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. +Each one share of Series A Preferred Stock will automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. Each share of Series A Preferred Stock is entitled to ten votes on each matter submitted to Matador’s shareholders for vote. Beginning on August 27, 2015 and until such time as the Series A Preferred Stock is converted to common stock, the holders will be entitled to a quarterly dividend of $1.80 per share. Neither the issuance of the Series A Preferred Stock nor the common stock issued in connection with this business combination will be registered under the Securities Act of 1933, as amended, and neither the Series A Preferred Stock nor such common stock may be offered or sold in the United States absent such registration or an applicable exemption from registration requirements. As part of this transaction, the Company has entered into a registration rights agreement with HEYCO Energy Group, Inc. providing certain demand and piggyback registration rights, with demand registration rights exercisable on February 27, 2016. +In January 2015 , the Company granted awards of 113,289 shares of restricted stock and options to purchase 607,995 shares of the Company’s common stock at an exercise price of $22.01 per share to certain of its employees. The fair value of these awards was approximately $8.4 million . All of these awards vest over a term of three years. +Subsequent to December 31, 2014 , the Company has entered into several new commitments to participate in the drilling and completion of various non-operated wells. If all of the wells are drilled and completed as proposed, the Company’s minimum aggregate commitments for participation in these wells were approximately $17.1 million at February 27, 2015 . +F- 37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2014, 2013 and 2012 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2014, 2013 and 2012 (in thousands). +Year Ended December 31, +2014 +2013 +2012 +Property acquisition costs +Proved +$ +2,728 +$ +176 +$ +— +Unproved and unevaluated +78,484 +64,305 +28,672 +Exploration costs +156,178 +99,104 +115,084 +Development costs +372,982 +209,956 +190,891 +Total costs incurred +$ +610,372 +$ +373,541 +$ +334,647 +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2014, 2013 and 2012 , essentially all of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and installing production facilities. +Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $4.0 million , $1.5 million and $1.2 million for the years ended December 31, 2014, 2013 and 2012 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $6.4 million , $3.7 million and $2.6 million of these internal costs in 2014 , 2013 and 2012 , respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $2.8 million , $1.9 million and $1.6 million of its interest expense for the years ended December 31, 2014 , 2013 and 2012 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Eagle Ford shale in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The Company’s oil and natural gas reserves estimates for the +F- 38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2014, 2013 and 2012 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +years ended December 31, 2014, 2013 and 2012 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per barrel and $4.350 per MMBtu, respectively. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.670 per MMBtu, respectively. For the period from January through December 2012 , these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2011 +3,794 +170,418 +32,196 +Revisions of prior estimates +(782 +) +(103,375 +) +(18,010 +) +Extensions and discoveries +8,687 +25,443 +12,927 +Production +(1,214 +) +(12,479 +) +(3,294 +) +Total at December 31, 2012 +10,485 +80,007 +23,819 +Revisions of prior estimates +(199 +) +78,812 +12,936 +Purchases of minerals in-place +— +170 +28 +Extensions and discoveries +8,209 +66,121 +19,231 +Production +(2,133 +) +(12,915 +) +(4,285 +) +Total at December 31, 2013 +16,362 +212,195 +51,729 +Revisions of prior estimates +(1,196 +) +164 +(1,169 +) +Purchases of minerals in-place +10 +433 +82 +Extensions and discoveries +12,328 +69,566 +23,921 +Production +(3,320 +) +(15,303 +) +(5,870 +) +Total at December 31, 2014 +24,184 +267,055 +68,693 +Proved Developed Reserves +December 31, 2011 +1,419 +56,547 +10,843 +December 31, 2012 +4,764 +54,040 +13,771 +December 31, 2013 +8,258 +53,458 +17,168 +December 31, 2014 +14,053 +102,795 +31,185 +Proved Undeveloped Reserves +December 31, 2011 +2,375 +113,871 +21,353 +December 31, 2012 +5,721 +25,967 +10,048 +December 31, 2013 +8,104 +158,737 +34,561 +December 31, 2014 +10,131 +164,260 +37,508 +F- 39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2014, 2013 and 2012 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2014, 2013 and 2012 . +The Company’s proved oil and natural gas reserves increased to 68,693 MBOE at December 31, 2014 from 51,729 MBOE at December 31, 2013 . The Company’s proved oil and natural gas reserves increased by 22,834 MBOE and the Company produced 5,870 MBOE during the year ended December 31, 2014 , resulting in a net increase of 16,964 MBOE. An increase of 23,921 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and in the Wolfcamp and Bone Spring plays in the Permian Basin in West Texas and Southeast New Mexico, plus additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves decreased by 1,169 MBOE during the year as a result of revisions to previous estimates, primarily downward revisions of proved undeveloped oil reserves on certain of the Company’s undeveloped locations in the Eagle Ford shale play in South Texas in 2014 . The Company also purchased minerals in-place with proved reserves of 82 MBOE in 2014 . The Company’s proved developed oil and natural gas reserves increased to 31,185 MBOE at December 31, 2014 from 17,168 MBOE at December 31, 2013 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale and in the Wolfcamp and Bone Spring plays in the Permian Basin plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2014 , the Company’s proved reserves were made up of approximately 35% oil and 65% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 51,729 MBOE at December 31, 2013 from 23,819 MBOE at December 31, 2012 . The Company’s proved oil and natural gas reserves increased by 32,195 MBOE and the Company produced 4,285 MBOE during the year ended December 31, 2013 , resulting in a net increase of 27,910 MBOE. An increase of 19,231 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves increased by 12,936 MBOE during the year as a result of revisions to previous estimates, primarily upward revisions in the Company’s proved undeveloped natural gas reserves resulting from higher natural gas prices in 2013 . The Company also purchased minerals in-place with proved reserves of 28 MBOE in 2013. The Company’s proved developed oil and natural gas reserves increased to 17,168 MBOE at December 31, 2013 from 13,771 MBOE at December 31, 2012 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2013 , the Company’s proved reserves were made up of approximately 32% oil and 68% natural gas and were approximately 33% proved developed and approximately 67% proved undeveloped. +The Company’s proved oil and natural gas reserves decreased to 23,819 MBOE at December 31, 2012 from 32,196 MBOE at December 31, 2011 . The Company’s proved oil and natural gas reserves decreased by 5,083 MBOE and the Company produced 3,294 MBOE during the year ended December 31, 2012 , resulting in a net decrease of 8,377 MBOE. An increase of 12,927 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas. The Company’s oil and natural gas reserves decreased by 18,010 MBOE during the year as a result of revisions to previous estimates, primarily resulting from lower natural gas prices in 2012 . The Company’s proved developed oil and natural gas reserves increased to 13,771 MBOE at December 31, 2012 from 10,843 MBOE at December 31, 2011 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2012 , the Company’s proved reserves were made up of approximately 44% oil and 56% natural gas and were approximately 58% proved developed and 42% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +F- 40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2014, 2013 and 2012 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +As noted previously, for the period from January through December 2014 , the unweighted, arithmetic average of first-day-of-the-month oil and natural gas prices were $91.48 per barrel and $4.350 per MMBtu, respectively. For the period from January through December 2013 , the comparable average oil and natural gas prices were $93.42 per barrel and $3.670 per MMBtu, respectively. For the period from January through December 2012 , the comparable average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and marketing costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012 (in thousands). +Year Ended December 31, +2014 +2013 +2012 +Future cash inflows +$ +3,197,317 +$ +2,316,626 +$ +1,273,882 +Future production costs +(803,662 +) +(666,450 +) +(325,413 +) +Future development costs +(553,799 +) +(507,923 +) +(244,283 +) +Future income tax expense +(321,088 +) +(181,041 +) +(77,821 +) +Future net cash flows +1,518,768 +961,212 +626,365 +10% annual discount for estimated timing of cash flows +(605,449 +) +(382,544 +) +(231,729 +) +Standardized measure of discounted future net cash flows +$ +913,319 +$ +578,668 +$ +394,636 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012 (in thousands). +Year Ended December 31, +2014 +2013 +2012 +Balance, beginning of period +$ +578,668 +$ +394,636 +$ +215,473 +Net change in sales and transfer prices and in production (lifting) costs related to future production +87,067 +(97,511 +) +(60,892 +) +Changes in estimated future development costs +(150,447 +) +(233,232 +) +16,937 +Sales and transfers of oil and natural gas produced during the period +(283,187 +) +(209,338 +) +(116,142 +) +Purchases of reserves +1,838 +176 +— +Net change due to extensions and discoveries +537,472 +386,696 +358,159 +Net change due to revisions in estimates of reserves quantities +(26,263 +) +260,148 +(56,850 +) +Previously estimated development costs incurred during the period +187,459 +106,348 +9,750 +Accretion of discount +65,518 +36,184 +24,873 +Other +5,492 +(371 +) +(290 +) +Net change in income taxes +(90,298 +) +(65,068 +) +3,618 +Standardized measure of discounted future net cash flows +$ +913,319 +$ +578,668 +$ +394,636 +F- 41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2014, 2013 and 2012 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2014 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2014 +Oil and natural gas revenues +$ +93,110 +$ +96,617 +$ +99,054 +$ +78,931 +Realized gain (loss) on derivatives +10,479 +(701 +) +(2,913 +) +(1,843 +) +Unrealized gain (loss) on derivatives +50,351 +16,293 +(5,234 +) +(3,108 +) +Expenses +78,675 +65,680 +60,840 +46,723 +Other expense +1,018 +406 +1,207 +1,358 +Income before income taxes +74,247 +46,123 +28,860 +25,899 +Income tax provision +27,701 +16,504 +10,634 +9,536 +Net income +46,546 +29,619 +18,226 +16,363 +Net loss attributable to non-controlling interest in subsidiary +17 +— +— +— +Net income attributable to +Matador Resources Company shareholders +$ +46,563 +$ +29,619 +$ +18,226 +$ +16,363 +Earnings per common share attributable to Matador Resources Company shareholders +Basic +$ +0.63 +$ +0.40 +$ +0.27 +$ +0.25 +Diluted +$ +0.63 +$ +0.40 +$ +0.26 +$ +0.25 +The following table presents selected unaudited quarterly financial information for 2013 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2013 +Oil and natural gas revenues +$ +69,664 +$ +81,868 +$ +58,179 +$ +59,319 +Realized (loss) gain on derivatives +(390 +) +(1,165 +) +254 +392 +Unrealized (loss) gain on derivatives +(606 +) +(9,327 +) +7,526 +(4,825 +) +Expenses (1) +45,513 +46,736 +39,054 +69,141 +Other expense +724 +1,972 +1,754 +1,204 +Income (loss) before income taxes +22,431 +22,668 +25,151 +(15,459 +) +Income tax provision +7,056 +2,563 +32 +46 +Net income (loss) +15,375 +20,105 +25,119 +(15,505 +) +Net loss attributable to non-controlling interest in subsidiary +— +— +— +— +Net income (loss) attributable to +Matador Resources Company shareholders +$ +15,375 +$ +20,105 +$ +25,119 +$ +(15,505 +) +Earnings (loss) per common share attributable to Matador Resources Company shareholders +Basic +$ +0.23 +$ +0.35 +$ +0.45 +$ +(0.28 +) +Diluted +$ +0.23 +$ +0.35 +$ +0.45 +$ +(0.28 +) +_________________________ +(1) Expenses for March 31, 2013 include a ceiling test impairment charge of $21.3 million. +F- 42 \ No newline at end of file diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/filing_metadata.csv b/raw/filings/0001520006/2014/0001520006-15-000008/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..63ac3764b7b3d6f2575ae5fe84a27ebb0899cd79 --- /dev/null +++ b/raw/filings/0001520006/2014/0001520006-15-000008/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2015-03-02,2014-12-31,2015-03-03T03:21:45.000Z,0001520006-15-000008,mtdr10-k12312014.htm,10-K,18990428,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000152000615000008/mtdr10-k12312014.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000615000008/,2014,2014,1 diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/item1.txt b/raw/filings/0001520006/2014/0001520006-15-000008/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..a322f3d8d5cacca7618b84b57f3cd2d5dabe7161 --- /dev/null +++ b/raw/filings/0001520006/2014/0001520006-15-000008/item1.txt @@ -0,0 +1,1036 @@ +Item 1. Business. +In this Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. +Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering. +For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Permian Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• maintain our financial discipline; and +• pursue opportunistic acquisitions. +The successful execution of our business strategies in 2014 led to significant increases in our oil and natural gas revenues and Adjusted EBITDA, oil and natural gas production and proved oil and natural gas reserves, and the associated increase in the PV-10 of our proved oil and natural gas reserves. We also significantly increased our leasehold position in the Permian Basin and added to our acreage position in the Eagle Ford shale. Adjusted EBITDA and PV-10 are non-GAAP financial measures. For a definition of such terms and a reconciliation to the most directly comparable GAAP financial measures, see “Selected Financial Data — Non-GAAP Financial Measures” and “—Estimated Proved Reserves.” +3 +Table of Contents +2014 Highlights +Increased Oil and Natural Gas Revenues and Adjusted EBITDA +Our oil and natural gas revenues for the year ended December 31, 2014 were the highest achieved in any fiscal year in the Company’s history. Our oil and natural gas revenues increased $98.7 million to $367.7 million in 2014 , which represents an increase of 37% from 2013. This revenue increase was primarily driven by a significant increase in our oil and natural gas production in 2014 . Our Adjusted EBITDA of $262.9 million for 2014 was an increase of 37% , as compared to our Adjusted EBITDA of $191.8 million for 2013. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2014 , we achieved record oil, natural gas and average daily oil equivalent production. In 2014 , we produced 3.3 million barrels of oil, an increase of 56% , as compared to 2.1 million barrels of oil produced in 2013. We also produced 15.3 Bcf of natural gas, an increase of 18% from 12.9 Bcf of natural gas produced in 2013. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, an increase of 37% , as compared to 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, for the year ended December 31, 2013 . The increase in oil production was primarily attributable to our ongoing development activities in the Eagle Ford shale, as well as better-than-expected initial production contributions from wells drilled in the Permian Basin during 2014 . We achieved this increased oil production despite having as much as 15% to 20% of our production capacity shut in at various times during 2014 while offsetting wells were being drilled and completed and pipeline connections were being made. The increase in natural gas production was primarily attributable to initial production contributions from wells drilled in the Permian Basin, as well as non-operated Haynesville shale wells drilled on our Elm Grove properties in Northwest Louisiana. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2014 , as compared to 50% for the year ended December 31, 2013 and 37% for the year ended December 31, 2012. +Increased Oil and Natural Gas Reserves +At December 31, 2014 , our estimated total proved oil and natural gas reserves were 68.7 million BOE, including 24.2 million Bbl of oil and 267.1 Bcf of natural gas, which is an increase of 33% from December 31, 2013 . The associated PV-10 of our estimated total proved oil and natural gas reserves increased 59% to $1.04 billion at December 31, 2014 from $655.2 million at December 31, 2013 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 48% to 24.2 million Bbl at December 31, 2014 from 16.4 million Bbl at December 31, 2013 . This growth in oil reserves was primarily attributable to our drilling programs in both the Eagle Ford shale and the Permian Basin during 2014 . Our proved natural gas reserves increased 26% to 267.1 Bcf at December 31, 2014 from 212.2 Bcf at December 31, 2013 . This increase in proved natural gas reserves was primarily attributable to our operated drilling activity in the Permian Basin and non-operated drilling activity in the Haynesville shale during 2014. +At December 31, 2014 , proved developed reserves included 14.1 million Bbl of oil and 102.8 Bcf of natural gas, and proved undeveloped reserves included 10.1 million Bbl of oil and 164.3 Bcf of natural gas. Proved developed reserves comprised 45% and proved oil reserves comprised 35% of our total proved oil and natural gas reserves, respectively, at December 31, 2014 . Proved developed reserves comprised 33% of our total reserves and proved oil reserves comprised 32% of our total proved oil and natural gas reserves, respectively, at December 31, 2013 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to manage more effectively operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past three years, and, during 2014 , we began to apply what we learned from the Eagle Ford shale, as well as from our Haynesville shale experience, to the delineation and development of our Permian Basin acreage. +We continued our strong execution in the Eagle Ford shale during 2014, and the Eagle Ford continued to drive our production and revenue growth in 2014. During 2014, 65% of our total daily oil equivalent production, or 10,501 BOE per day, consisting of 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, was produced from the Eagle Ford shale. +4 +Table of Contents +Over the past three years, we have progressed from drilling Eagle Ford wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In 2014, approximately 90% of our Eagle Ford wells were drilled in multi-well batch mode using drilling rigs equipped with a “walking” package, and as a result, we continued to improve both drilling times and costs. Recent wells drilled on our western Eagle Ford acreage in La Salle County, Texas had drilling times from spud to total depth of seven to 10 days per well. Average drilling and completions costs in this area have been reduced to $5.5 to $6.5 million per well. On our central Eagle Ford acreage in Karnes County, Texas, significant drilling improvements, including the use of the “walking” rig, were made during 2014 that reduced drilling times by several days, especially during the second half of 2014. We anticipate that the combination of further operational improvements and service cost reductions may yield drilling and completion costs at or below $6.0 million on wells drilled on our central Eagle Ford acreage during 2015. +During 2014, we made further improvements to our Eagle Ford fracture treatment design, with the goal of developing a treatment design specific to wells developed on 40- to 50-acre spacing. The treatments were designed to create higher fracture conductivity closer to the wellbore, more consistent fracture geometry and more overall fractures. We believe that we achieved these design objectives by (1) increasing the fluid volumes pumped to 40 Bbl per foot and the total proppant volumes pumped to 2,000 pounds per foot of completed lateral length or more, (2) tightening the perforation cluster spacing and (3) further modifying the perforation geometry. These “Generation 7” fracture treatments are typically resulting in significant improvements in initial well productivity and overall well performance for our Eagle Ford wells as compared to earlier generation fracture treatment designs using less fluid and proppant and different perforation and cluster geometries. We also believe that initiating the use of gas lift early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. In addition, as our development program matured in 2014, most of our newly completed Eagle Ford wells were able to use existing tank batteries and facilities, resulting in significant cost savings as compared to the need to construct new facilities in previous years. +We substantially increased our acreage position in the Permian Basin during 2014, and at December 31, 2014, we held approximately 92,700 gross (66,100 net) acres primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We also continued the exploration and delineation of our Permian Basin acreage, operating one to two drilling rigs on our acreage there in 2014 and testing six different Bone Spring and Wolfcamp target intervals. The initial performance of most of the wells we have drilled and completed thus far in our three main prospect areas—the Wolf prospect area in Loving County, Texas, the Ranger prospect area in Lea County, New Mexico and the Rustler Breaks prospect area in Eddy County, New Mexico—have exceeded our expectations. As a result, our Permian Basin properties are becoming an increasingly important component of our asset portfolio, and the Permian Basin will be our primary area of focus in 2015. Our average daily oil equivalent production from the Permian Basin grew 10-fold from 260 BOE per day in the fourth quarter of 2013 to 2,600 BOE per day in the fourth quarter of 2014, comprising 11% of our total oil equivalent production for all of 2014. We expect our Permian Basin production to increase throughout 2015 as we continue the delineation and development of these properties. +We did not drill any operated Haynesville shale wells during 2014, but we did participate in a number of non-operated wells drilled in the Haynesville shale in Northwest Louisiana. The most impactful were the Haynesville wells drilled and completed by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove properties in southern Caddo Parish. In 2014, Chesapeake completed and placed on production 14 gross wells, comprising 3.3 wells net to Matador’s working interest. These wells had initial production rates ranging from 8 to 14 MMcf of natural gas per day (gross) and estimated ultimate recoveries of 8 to 12 Bcf per well. As these wells were placed on production in 2014, our Haynesville natural gas production grew more than three-fold from 11.1 MMcf per day in the fourth quarter of 2013 to approximately 35.0 MMcf per day in the fourth quarter of 2014. In January 2015, Chesapeake completed and placed on production an additional three gross (0.5 net) wells at Elm Grove. As a result, our Haynesville natural gas production grew to over 50 MMcf of natural gas per day as of February 27, 2015. +Acreage Acquisitions +During 2014 , we acquired approximately 29,300 gross ( 21,800 net) additional acres in the Permian Basin in Southeast New Mexico and West Texas. These acreage acquisitions brought our total Permian Basin acreage position to approximately 92,700 gross (66,100 net) acres as of December 31, 2014 . Between January 1 and December 31, 2014 , we also acquired approximately 3,200 gross ( 3,000 net) acres in the Eagle Ford shale play in South Texas. +As noted below in “— Recent Developments”, in January 2015, we entered into a definitive agreement pursuant to which one of our wholly-owned subsidiaries would merge with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico owned by HEYCO with our Delaware Basin operations (the “HEYCO Merger”). The HEYCO Merger included approximately 58,600 gross (18,200 net) acres. Upon the closing of the HEYCO Merger on February 27, 2015, our Permian Basin acreage position increased to approximately 152,400 gross ( 85,400 net) acres. +5 +Table of Contents +Issuance of Common Stock +On May 29, 2014, we completed a public offering of 7,500,000 shares of our common stock. After deducting direct offering costs totaling approximately $0.6 million , we received net proceeds of approximately $181.3 million . We used a portion of the net proceeds to repay $180.0 million in outstanding borrowings under our third amended and restated credit agreement (the “Credit Agreement”), which amounts were subsequently reborrowed in accordance with the terms of that facility. The remaining $1.3 million of the offering net proceeds was used to fund working capital requirements. +Recent Developments +On January 19, 2015, we entered into a definitive agreement pursuant to which one of our wholly-owned subsidiaries would merge with HEYCO, combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico owned by HEYCO with our Delaware Basin operations. The HEYCO Merger closed on February 27, 2015. As consideration for the HEYCO Merger, we paid approximately $21.6 million in cash, assumed debt obligations of approximately $12.0 million and issued 3,300,000 shares of the Company’s common stock and 150,000 shares of a new series of the Company’s convertible preferred stock to HEYCO Energy Group, Inc. In addition, we paid an additional $3.0 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. Pursuant to the terms of the merger agreement, 125,000 of the 150,000 shares of Series A Preferred Stock (as defined below) issued upon the closing of the HEYCO Merger were placed into escrow to satisfy post-closing adjustments to the merger consideration for any title or environmental defects on the assets we added. +As part of the consideration for the acquisition, we issued 150,000 shares of Series A Convertible Preferred Stock (the “Series A Preferred Stock”). Each share of Series A Preferred Stock is entitled to ten votes on each matter submitted to our shareholders for vote. The holders of Series A Preferred Stock will vote, on an as-converted basis, together with the holders of common stock as a single class, except with respect to matters that would adversely affect the holders of Series A Preferred Stock as compared to the holders of common stock, in which case the holders of Series A Preferred Stock will vote as a separate class. Beginning on August 27, 2015 and until such time as the Series A Preferred Stock is converted to common stock, the holders will be entitled to a quarterly dividend of $1.80 per share. The private placement of the Series A Preferred Stock and the common stock issued in connection with the HEYCO Merger was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. +Each share of Series A Preferred Stock will automatically convert into ten shares of our common stock, subject to customary anti-dilution adjustments, upon the vote and approval by our shareholders of an amendment to our Amended and Restated Certificate of Formation to increase the number of shares of authorized common stock (the “Charter Amendment”). On February 25, 2015, we filed a definitive proxy statement with the Securities and Exchange Commission and began mailing to our shareholders such proxy materials related to a special meeting of shareholders to be held on April 2, 2015 at 9:30 a.m., Central Time, for the purpose of approving the Charter Amendment. All shareholders of record as of the close of business on February 18, 2015 will be entitled to vote at the special meeting. +As part of the merger consideration, one of our wholly-owned subsidiaries, MRC Delaware Resources, LLC (“MRC Delaware”), assumed approximately $12.0 million of HEYCO’s indebtedness (the “Assumed Indebtedness”). Such Assumed Indebtedness is evidenced by a loan agreement and a promissory note executed by MRC Delaware in favor of PlainsCapital Bank (“PlainsCapital”) in the principal amount of $12,500,000. Outstanding borrowings are secured by mortgages on substantially all of the oil and natural gas properties held by MRC Delaware after the HEYCO Merger and are subject to a borrowing base of approximately $12.0 million. The principal and interest under the promissory note are due and payable on July 24, 2015 and outstanding borrowings under the promissory note bear interest at a variable annual rate equal to the prime rate, but in no event less than 3.25%. The Company executed a guaranty (the “Guaranty”) pursuant to which the Company has agreed to guarantee MRC Delaware’s prompt, complete and full payment of the principal and interest and other fees and obligations relating to the Assumed Indebtedness. In addition, the Company has agreed to comply with a provision of the loan agreement governing the Assumed Indebtedness that sets forth a funded debt to EBITDA (defined as net income before interest, taxes, depletion, depreciation, intangible drilling costs and amortization) ratio covenant, which is defined as total funded debt outstanding for the Company and its consolidated subsidiaries divided by a rolling four quarter EBITDA calculation for the Company and its consolidated subsidiaries, of 4.25 or less. A failure by the Company to meet the requirements of such covenant, or a failure to otherwise comply with the payment guaranty provisions set forth in the Guaranty, will constitute an event of default under our Credit Agreement. +In connection with the HEYCO Merger, we entered into a registration rights agreement with HEYCO Energy Group, Inc., pursuant to which we will be required, upon request from HEYCO Energy Group, Inc. at any time on or after February 27, 2016, to file and maintain a shelf registration statement with respect to the resale of the shares of common stock issued as consideration for the HEYCO Merger and upon conversion of the Series A Preferred Stock, respectively, and to provide piggyback registration rights for such shares of common stock. +6 +Table of Contents +As noted above, the HEYCO Merger added approximately 58,600 gross (18,200 net) acres in the Delaware Basin in Lea and Eddy Counties, New Mexico, strategically located between our existing acreage in the Ranger and Rustler Breaks prospect areas. Over 95% of the HEYCO acreage position consists of state and federal leases, most with favorable net revenue interests greater than 80% and some as high as 87.5%. Essentially all of the acreage is held by production from existing wells and production units. +Principal Areas of Interest +Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Eagle Ford shale play in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas and the Haynesville shale play in Northwest Louisiana. During 2014 , we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin as we sought to continue to increase our oil production and reserves. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2014 , essentially all of our efforts were focused on unconventional plays. +At December 31, 2014 , our principal areas of interest consisted of the Eagle Ford shale play in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where we are testing the Meade Peak shale. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2014 : +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +South Texas: +Eagle Ford (4) +39,871 +29,686 +117 +99.2 +278 +240.4 +22,257 +71.8 +10,501 +NW Louisiana/E Texas: +Haynesville +21,295 +13,571 +183 +16.8 +471 +111.9 +32,183 +30.0 +3,290 +Cotton Valley (5) +22,362 +19,748 +97 +62.4 +71 +50.1 +1,223 +100.0 +501 +Area Total (6) +27,251 +24,396 +280 +79.2 +542 +162.0 +33,406 +32.6 +3,791 +Permian Basin: +SE New Mexico, West Texas (7) +92,682 +66,076 +31 +19.2 +1,445 +959.5 +13,030 +33.1 +1,790 +Other: +Wyoming, Utah, Idaho +75,674 +35,732 +— +— +— +— +— +— +— +Total +235,478 +155,890 +428 +197.6 +2,265 +1,361.9 +68,693 +45.4 +16,082 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2014 . The total net engineered drilling locations is calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2014 , these engineered drilling locations included 40 gross (32.6 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford, 19 gross (15.6 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Permian Basin and 127 gross (20.6 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formation at December 31, 2014 . +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes two wells producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(5) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(6) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +(7) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware and Avalon plays on our acreage in the Permian Basin at December 31, 2014 . +7 +Table of Contents +We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, BHP Billiton and others. At December 31, 2014 , we were the operator for over 90% of our Eagle Ford acreage and approximately two-thirds of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. At December 31, 2014 , we also operated the majority of our acreage in the Permian Basin in Southeast New Mexico and West Texas, as well as all of our acreage in Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interests are often relatively small, particularly in the Haynesville shale. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2014 , our properties included approximately 39,900 gross (29,700 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 77% of our Eagle Ford acreage was held by production at December 31, 2014 , and approximately 96% of our Eagle Ford acreage was either held by production at December 31, 2014 or not burdened by lease expirations before 2016 . During the year ended December 31, 2014 , we acquired approximately 3,200 gross ( 3,000 net) acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This acreage more than replaced the acreage upon which we drilled and established oil and natural gas production and reserves in the Eagle Ford during 2014 . +At December 31, 2014 , we had 117 gross ( 99.2 net) wells producing from the Eagle Ford shale in South Texas. We had drilled and completed a total of 97 gross (93.2 net) Eagle Ford wells on our operated properties, and we had also participated in 20 gross (6.0 net) Eagle Ford wells with co-working interest owners on certain of our non-operated Eagle Ford properties. During 2014 , approximately 56% of our total capital expenditures of $610.4 million were directed to our operations in the Eagle Ford shale, as we continued executing our strategy to significantly increase our oil production and oil reserves. As a result of both lower oil and natural gas prices in early 2015 and the fact that, at December 31, 2014 , approximately 96% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2016, we plan to temporarily suspend our Eagle Ford development program after the first quarter of 2015 . We expect to run two operated drilling rigs in the Eagle Ford during the first quarter of 2015, but then do not plan to drill any operated wells in the Eagle Ford for the remainder of the year. We have allocated approximately $90.0 million, or 26%, of our 2015 capital expenditures budget of $350.0 million (excluding capital expenditures associated with the HEYCO Merger) to our anticipated drilling and completion activities in the Eagle Ford, as well as for the acquisition of additional leasehold interests in this area. +During the year ended December 31, 2014 , we completed and began producing oil and natural gas from 44 gross (36.7 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 36 gross (34.5 net) operated and eight gross (2.2 net) non-operated wells. As we completed and began producing oil and natural gas from these wells during 2014 , our Eagle Ford production increased significantly. For the year ended December 31, 2014 , 65% of our total daily oil equivalent production, or 10,501 BOE per day, including 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, was produced from the Eagle Ford shale. The vast majority of our oil production in 2014 and 2013 was attributable to the Eagle Ford shale. The Eagle Ford shale contributed approximately 85% of our daily oil production and approximately 39% of our daily natural gas production during 2014 , as compared to approximately 98% of our daily oil production and approximately 42% of our daily natural gas production during 2013 . During the year ended December 31, 2013 , approximately 70% of our daily oil equivalent production, or 8,225 BOE per day, including 5,748 Bbl of oil per day and 14.9 MMcf of natural gas per day, was +8 +Table of Contents +attributable to the Eagle Ford shale. During the year ended December 31, 2012, only about 8% of our daily oil equivalent production, or 548 BOE per day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past several years reflects our ongoing drilling and completion operations in South Texas. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich natural gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other heavier natural gas liquids components. Our Eagle Ford wells typically yield five to seven gallons of natural gas liquids per Mcf of natural gas produced at the wellhead depending on the specific property. +At December 31, 2014 , approximately 32% of our estimated total proved oil and natural gas reserves, or 22.3 million BOE, was attributable to the Eagle Ford shale, including approximately 16.1 million Bbl of oil and 36.9 Bcf of natural gas. Our total proved reserves attributable to the Eagle Ford shale increased approximately 10% to 22.3 million BOE for the year ended December 31, 2014 , as compared to 20.2 million BOE for the year ended December 31, 2013 . As a result of our drilling and completions schedule in 2014, and particularly our drilling of infill wells on 40- to 50-acre spacing, many of the Eagle Ford wells we drilled during 2014 were identified as proved developed non-producing (“PDNP”) or proved undeveloped (“PUD”) reserves at December 31, 2013 . Our Eagle Ford total proved reserves at December 31, 2014 comprised approximately 67% of our proved oil reserves and 14% of our proved natural gas reserves, as compared to approximately 93% of our proved oil reserves and 14% of our proved natural gas reserves at December 31, 2013 . The PV-10 of our total proved reserves in the Eagle Ford shale was $603.8 million , or approximately 58% of the PV-10 of our total proved reserves of $1.04 billion at December 31, 2014 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +At December 31, 2014 , we have identified 278 gross ( 240.4 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. As a result of the development wells we drilled during 2014, we anticipate the Eagle Ford wells to be drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. While there are some locations that we would choose not to drill with oil prices near $50 per Bbl as they have been in early 2015, almost all of these locations are associated with portions of our acreage that are already held by production at December 31, 2014 or not burdened by near-term lease expirations. As a result, these engineered drilling locations remain available to be developed by us at a future time when commodity prices improve, drilling and completion costs decline further or new technologies are developed that increase the expected recoveries. At December 31, 2014 , these 278 gross (240.4 net) identified drilling locations included only 40 gross (32.6 net) locations to which we have assigned proved undeveloped reserves. +We believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past three years. During this time, we have progressed from drilling wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In August 2013, we began drilling certain wells on our western Eagle Ford acreage in La Salle County, Texas from batch-drilled pads using a drilling rig equipped with a “walking” package, and in April 2014, we began using a “walking” rig on our central Eagle Ford acreage in Karnes and Wilson Counties. As a result, we have improved drilling times and costs in both areas. We have realized drilling cost savings on wells drilled from batch-drilled pads of approximately 20% per foot drilled compared to wells drilled from single-well pads and approximately 10% per foot drilled compared to wells drilled from multi-well pads. As a result of batch mode development and other operational improvements, we estimate that we have saved approximately $600,000 per well on drilling costs, as compared to wells drilled from single-well pads. Our development strategy in 2014 used three wells per batch pad, but the majority of our Eagle Ford wells, which will be drilled in the first quarter of 2015, will be developed with four wells per batch pad. We expect this development approach to yield further incremental cost savings. +During 2014, most wells drilled on our western Eagle Ford acreage in La Salle County, Texas had drilling times from spud to total depth of seven to 10 days per well. Average drilling and completions costs in this area have been reduced to $5.5 to $6.5 million per well. On our central Eagle Ford acreage in Karnes County, Texas, significant drilling improvements, including the use of the “walking” rig, made during 2014 also reduced drilling times by several days, especially during the second half of 2014. We anticipate that the combination of further operational improvements and service cost reductions may yield drilling and completion costs at or below $6.0 million on wells drilled and completed in our central Eagle Ford acreage during 2015. +9 +Table of Contents +During 2014, we also made further improvements to our Eagle Ford fracture treatment design, with the goal of developing a treatment design specific to wells developed on 40- to 50-acre spacing. The treatments were designed to create higher fracture conductivity closer to the wellbore, more consistent fracture geometry and more overall fractures. We believe that we achieved these design objectives by (1) increasing the fluid volumes pumped to 40 Bbl per foot and the total proppant volumes pumped to 2,000 pounds per foot of completed lateral length or more, (2) tightening the perforation cluster spacing and (3) further modifying the perforation geometry. These “Generation 7” fracture treatments are typically resulting in significant improvements in initial well productivity and overall well performance as compared to earlier generation fracture treatment designs using less fluid and proppant and different perforation and cluster geometries. We also believe that initiating the use of gas lift early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. In addition, as our development program matured in 2014, most of our newly completed Eagle Ford wells were able to use existing tank batteries and facilities, resulting in significant cost savings as compared to the need to construct new facilities in previous years. +We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas which are held by production and which we believe may be prospective for the Buda formation. We believe our acreage is located within the extension of a trend where encouraging drilling by other operators has occurred in the Buda just southwest of our leasehold position. We have acquired a 3-D seismic survey over our acreage, and at February 27, 2015 , we were evaluating a series of seismic attributes that are similar to fracture patterns observed in cores from other wells in the area and from our drilling of previous wells on the acreage in 2012 and which are consistent with regional mapping. At December 31, 2014 , we had not drilled any Buda wells nor had we included any Buda locations in our future drilling locations. +Southeast New Mexico and West Texas — Permian Basin +The Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and intense hydraulic fracturing techniques. +In the western part of the Permian Basin (also known as the Delaware Basin), the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are proven to be the source rocks for oil and natural gas produced in the basin. Historically, production has come from the “conventional” reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-interval hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp “A” through “D”. +During 2014 , we acquired an additional 29,300 gross ( 21,800 net) acres in Southeast New Mexico and West Texas, and at December 31, 2014 , our leasehold position in the Permian Basin included approximately 92,700 gross (66,100 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. With the closing of the HEYCO Merger on February 27, 2015, our Permian Basin acreage position increased to approximately 152,400 gross ( 85,400 net) acres. We consider the vast majority of our Permian Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon shale and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. +During the year ended December 31, 2014, we continued the exploration and delineation of our Permian Basin acreage. We completed and began producing oil and natural gas from 11 gross (9.6 net) wells in the Permian Basin, including ten gross (9.5 net) operated wells and one gross (0.1 net) non-operated wells. The ten operated wells tested six different Bone Spring and Wolfcamp intervals. We completed and placed on production five wells in the Wolf prospect area in Loving County, Texas — four wells testing the Wolfcamp “X” sand at the top of the Wolfcamp interval and one well testing the Wolfcamp “A” interval +10 +Table of Contents +below the “X/Y” sands. Four operated wells in the Ranger prospect area in Lea County, New Mexico tested the Second Bone Spring, the Wolfcamp “D” and the Third Bone Spring. One operated well in the Rustler Breaks prospect area in Eddy County, New Mexico tested the Wolfcamp “B” interval. +In the Wolf prospect area in Loving County, Texas, the upper Wolfcamp “X” sand has proven to be highly productive, and the initial wells completed in this prospect continue to perform above our original projections. As of early February 2015, the Dorothy White #1H well, our first well in the Wolf prospect area, had produced 310,000 BOE (66% oil), including 203,000 Bbl of oil and 640 MMcf of natural gas, in just over one year of production and was still producing 450 Bbl of oil and 1.7 MMcf of natural gas per day. Other wells we have drilled near the Dorothy White #1H are similar. As of early February 2015, the Norton Schaub #1H had produced 122,000 BOE (69% oil) in approximately six months of production, including 84,000 Bbl of oil and 228 MMcf of natural gas, and was still producing 500 Bbl of oil per day and 1.6 MMcf of natural gas per day. The Johnson 44-02S-B53 #204H well drilled north of the Dorothy White #1H had produced 117,000 BOE (65% oil), including 75,000 Bbl of oil and 248 MMcf of natural gas, in just four months of production and in early February 2015 was producing 530 Bbl of oil per day and 1.8 MMcf of natural gas per day. By comparison, the Dorothy White #1H produced 110,000 BOE in its first four months of production. At the southern end of the Wolf prospect area, the Arno #1H well was also drilled and completed in the Wolfcamp “X” sand. This well tested 1,110 BOE per day (27% oil), including 300 Bbl of oil and 4.9 MMcf of natural gas per day at a flowing pressure of 4,100 pounds per square inch (“psi”) on a 26/64-inch choke. This well has only recently been placed on production after having been shut in awaiting a pipeline connection and the repair of a county road that was washed out during flooding in this area in late September 2014. In late December 2014, we also tested the Norton Schaub 84-TTT-B33 WF #2010H in the Wolf prospect area. During a 24-hour initial potential test, this well flowed 875 BOE per day (69% oil), including 608 Bbl of oil per day and 1.6 MMcf of natural gas per day at 2,600 psi on a 28/64-inch choke. The Norton Schaub 84-TTT-B33 WF #2010H was our first test of the Wolfcamp “A” interval, a more organically rich portion of the upper Wolfcamp below the “X/Y” sands. This was another encouraging test of a new Wolfcamp bench and indicates the Wolfcamp “A” may be another potential completion target in the upper Wolfcamp. +In the Ranger prospect area in Lea County, New Mexico, our first two Second Bone Spring completions have performed above our original projections for this area. As of early February 2015, the Ranger 33 State Com #1H had produced 184,000 BOE (91% oil) in its first 15 months of production and was still producing almost 200 Bbl of oil per day with gas-lift assist. The Pickard State 20-18-24 #1H, also drilled and completed in the Second Bone Spring, had produced 71,000 BOE (92% oil) in its first six months of production and was producing 330 Bbl of oil per day with gas-lift assist in early February 2015. We installed gas-lift assist on the Ranger 33 State Com #1H well within its first two months of production, and given the early success of the gas-lift assist on that well, the Pickard State 20-18-34 #1H well was also equipped with gas-lift assist within approximately 30 days of being placed on production. The use of gas-lift assist on these wells in the Ranger prospect area is just one example of a transfer of technology and lessons learned from our Eagle Ford development program in South Texas to the Permian Basin. +Also in the Ranger prospect area, we drilled and completed the Pickard State 20-18-34 #2H during 2014. This well was completed in the Wolfcamp “D” bench at approximately 12,000 feet true vertical depth, and we believe it to be the northernmost horizontal completion to date in the Wolfcamp “D” formation in the Delaware Basin. This well flowed 270 BOE per day, including 232 Bbl of oil and 225 Mcf of natural gas per day (86%) oil at 1,150 psi surface pressure during its 24-hour initial potential test. Although the results of the Pickard State 20-18-34 #2H were more modest than our other Permian Basin wells, we were encouraged by the geopressured nature of this horizon, other zones of interest in the well and because this well established the producibility of hydrocarbons from the Wolfcamp “D” interval. Finally, in the Ranger prospect area, the Jim Rolfe 22-18-34 RN #131H was drilled and completed in the Third Bone Spring sand. This well flowed 260 Bbl per day of oil and 102 Mcf of natural gas per day at 560 psi on a 28/64-inch choke during its 24-hour initial potential test. This well has been turned to sales, and we are in the process of evaluating artificial lift for this well. +In the Rustler Breaks prospect area in Eddy County, New Mexico, our first Wolfcamp “B” test, the Rustler Breaks 12-24-27 #1H has also performed better than our original projections for this area. As of early February 2015, this well had produced 134,000 BOE (43% oil) in about nine months of production and was producing about 140 barrels of oil per day and 1.3 MMcf of natural gas per day. +As we completed and began producing oil and natural gas from these wells during 2014 , our Permian Basin production increased significantly. Our average daily oil equivalent production from the Permian Basin grew ten-fold from 260 BOE per day in the fourth quarter of 2013 to 2,600 BOE per day in the fourth quarter of 2014. For the year ended December 31, 2014 , 11% of our daily oil equivalent production, or 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, was produced from the Permian Basin. The Permian Basin contributed approximately 14% of our daily oil production and approximately 7% of our daily natural gas production during 2014 , as compared to only about 1% of our daily oil production and approximately 0.1% of our daily natural gas production during 2013 . During the year ended December 31, 2013 , only about 1% of our daily oil equivalent production, or 84 BOE per day, including 78 Bbl of oil per day and 36 Mcf of natural gas per day, was attributable to the Permian Basin. +11 +Table of Contents +At December 31, 2014 , approximately 19% of our estimated total proved oil and natural gas reserves, or 13.0 million BOE, was attributable to the Permian Basin, including approximately 8.1 million Bbl of oil and 29.9 Bcf of natural gas. Our proved reserves attributable to the Permian Basin increased substantially to 13.0 million BOE for the year ended December 31, 2014 , as compared to 1.4 million BOE for the year ended December 31, 2013 . Our Permian Basin proved reserves at December 31, 2014 comprised approximately 33% of our proved oil reserves and 11% of our proved natural gas reserves, as compared to approximately 7% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2013 . The PV-10 of our proved reserves in the Permian Basin at December 31, 2014 was $246.2 million , or approximately 24% of the PV-10 of our total proved reserves of $1.04 billion . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +At December 31, 2014 , we had identified and engineered 1,445 gross ( 959.5 net) locations for potential future drilling on our Permian Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the Avalon and Delaware formations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Permian Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2014 do not yet include all portions of our acreage position, including the acreage associated with our Twin Lakes prospect area in Lea County, New Mexico or any locations associated with acreage from the HEYCO Merger. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Permian Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2014 , these potential future drilling locations included only 19 gross (15.6 net) locations in the Permian Basin to which we have assigned proved undeveloped reserves. +At December 31, 2014 , we were operating five contracted drilling rigs — two rigs in the Eagle Ford shale in South Texas and three rigs in the Permian Basin in Southeast New Mexico and West Texas. As a result of the sharp decline in commodity prices in recent months, we intend to scale back our drilling program during the first few months of 2015 to two rigs, both operating in the Permian Basin. In December 2014 and January 2015, we took delivery of two state-of-the-art, new-build rigs in the Permian Basin specifically configured for simultaneous operations and built to our specifications. These new rigs have full walking capabilities and high pressure circulating systems and are designed so that drilling operations can be conducted in the Wolfcamp formation while completion operations are performed in the Bone Spring or other intervals and vice versa—i.e., simultaneous drilling and completion operations. We expect the use of these rigs will result in additional operational efficiencies and will reduce the costs associated with our Permian Basin drilling program in 2015 . We have allocated approximately $245.0 million , or approximately 70% of our 2015 capital expenditure budget of $350.0 million (excluding capital expenditures associated with the HEYCO Merger), to our anticipated drilling and completion activities in the Permian Basin, as well as for the acquisition of additional leasehold interests in the area. Our 2015 Permian Basin drilling program will focus on the development of the Wolf prospect area, the further delineation of our Ranger and Rustler Breaks prospect areas and the integration of the HEYCO acreage. +Northwest Louisiana and East Texas +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2014 , although we did participate in the drilling and completion of 46 gross (4.2 net) non-operated Haynesville shale wells. In the first half of 2014, Chesapeake began the process of drilling up to an anticipated 45 gross (8.7 net) Haynesville shale wells on our Elm Grove acreage in southern Caddo Parrish, Louisiana, which we expect to continue through 2017. We retain the right to participate for up to a 25% working interest in all wells drilled on this property with our working interest proportionately reduced to our leasehold position in any individual drilling unit. After notifying us of its intent to conduct this drilling program, Chesapeake began actively drilling these properties during the second quarter of 2014, and had up to five rigs operating on these properties at any one time during 2014. Approximately 7% of our total capital expenditures of $610.4 million were associated with non-operated Haynesville shale wells in 2014, including those wells drilled by Chesapeake. These wells are being drilled and completed in a multi-well batch mode, and as of December 31, 2014 , Chesapeake had completed and placed 14 gross (3.3 net to us) wells on production. We do not plan to drill any operated Haynesville shale wells in 2015 , but we have budgeted capital expenditures of approximately $15.0 million for our anticipated participation in 33 gross (2.3 net) Haynesville shale wells that we anticipate may be drilled or completed and placed on production by other operators on certain of our non-operated properties in 2015 . Certain of these wells were already in progress at December 31, 2014 . The most significant of these non-operated Haynesville shale wells will be 10 gross (1.8 net) wells that we expect to be completed and placed on production by Chesapeake on our Elm Grove acreage in 2015. +At December 31, 2014 , we held approximately 27,300 gross (24,400 net) acres in Northwest Louisiana and East Texas, including 21,300 gross (13,600 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower +12 +Table of Contents +production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,700 gross (6,800 net) acres that we consider to be in the core area of the Haynesville play. +For the year ended December 31, 2014 , approximately 24% of our average daily oil equivalent production, or 3,791 BOE per day, including 17 Bbl of oil per day and 22.6 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 54% of our daily natural gas production, but oil production from these properties comprised only about 0.2% of our daily oil production during 2014 , as compared to approximately 58% of our daily natural gas production and approximately 0.3% of our daily oil production during 2013 . During the year ended December 31, 2013 , approximately 29% of our average daily oil equivalent production, or 3,431 BOE per day, including 17 Bbl of oil per day and 20.5 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2014 , approximately 47% of our daily natural gas production, or 19.7 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 7% , or 2.9 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2013 , approximately 48% of our daily natural gas production, or 17.0 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 10% , or 3.5 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2014 , approximately 47% of our estimated total proved reserves, or 32.2 million BOE, was attributable to the Haynesville shale with another 2% of our proved reserves, or 1.2 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +Although we averaged production of only about 19.7 MMcf of natural gas per day from the Haynesville shale in 2014 , our average daily natural gas production grew over three-fold during the year from almost 11.1 MMcf of natural gas per day in the fourth quarter of 2013 to approximately 35.0 MMcf of natural gas per day in the fourth quarter of 2014. This rapid growth in our Haynesville production was primarily due to the drilling and completion of 14 gross (3.3 net) non-operated Haynesville shale wells drilled by Chesapeake on our Elm Grove properties in Northwest Louisiana. Our Elm Grove properties are in what we believe is the core area of the Haynesville shale, and we anticipate the estimated ultimate recoveries from these wells at 8 to 12 Bcf each. Since January 1, 2015, Chesapeake has completed and placed on production three gross (0.5 net) additional wells. As a result, at February 27, 2015, we were producing over 50 MMcf of natural gas per day from the Haynesville shale. +At December 31, 2014 , we had identified and engineered 471 gross ( 111.9 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 471 gross ( 111.9 net) locations identified for future drilling on our Haynesville acreage, 396 gross (58.0 net) locations have been identified within the 13,700 gross (6,800 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2014 , these potential future drilling locations included 127 gross (20.6 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Haynesville and Middle Bossier Shales +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. +At December 31, 2014 , we had approximately 21,300 gross (13,600 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,700 gross (6,800 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that +13 +Table of Contents +area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2014 . +Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parrish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%. +Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations +Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. +All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2014 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We have identified 71 gross ( 50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2014 and do not plan to drill any of these locations in 2015 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2014 , we held an estimated 12,300 gross (9,800 net) leasehold and mineral acres by existing production in these areas. +Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale +At December 31, 2014 , we held leasehold interests in approximately 75,700 gross (35,700 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are the operator of this prospect. We have drilled and completed one horizontal well on this acreage, but as of December 31, 2014 , we had not established commercial natural gas production on this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2014 . We have no plans to drill on this acreage in 2015. +14 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production data for the years ended December 31, 2014, 2013 and 2012 : +Year Ended December 31, +2014 +2013 +2012 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +3,320 +2,133 +1,214 +Natural gas (Bcf) +15.3 +12.9 +12.5 +Total oil equivalent (MBOE) (1) +5,870 +4,285 +3,294 +Average daily production (BOE/d) (1) +16,082 +11,740 +9,000 +Average Sales Prices: +Oil, with realized derivatives (per Bbl) +$ +88.94 +$ +98.67 +$ +103.55 +Oil, without realized derivatives (per Bbl) +$ +87.37 +$ +99.79 +$ +101.86 +Natural gas, with realized derivatives (per Mcf) +$ +5.06 +$ +4.47 +$ +3.55 +Natural gas, without realized derivatives (per Mcf) +$ +5.08 +$ +4.35 +$ +2.59 +Operating Expenses (per BOE): +Production taxes and marketing +$ +5.65 +$ +4.89 +$ +3.54 +Lease operating +$ +8.75 +$ +9.04 +$ +8.56 +Depletion, depreciation and amortization +$ +22.95 +$ +22.96 +$ +24.43 +General and administrative +$ +5.48 +$ +4.85 +$ +4.42 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2014 from our primary operating areas: +Average Net Daily Production +Oil (Bbl/d) +Natural Gas (Mcf/d) +Oil Equivalent (BOE/d) (1) +Total Net Production (MBOE) (1) +Percentage of Total Net Production +South Texas: +Eagle Ford (2) +7,764 +16,423 +10,501 +3,833 +65.3 +% +NW Louisiana/E Texas: +Haynesville +— +19,740 +3,290 +1,201 +20.5 +% +Cotton Valley (3) +17 +2,903 +501 +183 +3.1 +% +Area Total +17 +22,643 +3,791 +1,384 +23.6 +% +Permian Basin: +SE New Mexico, West Texas +1,314 +2,859 +1,790 +653 +11.1 +% +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +9,095 +41,925 +16,082 +5,870 +100.0 +% +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(2) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +15 +Table of Contents +The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2013 from our primary operating areas: +Average Net Daily Production +Oil (Bbl/d) +Natural Gas (Mcf/d) +Oil Equivalent (BOE/d) (1) +Total Net Production (MBOE) (1) +Percentage of Total Net Production +South Texas: +Eagle Ford (2) +5,748 +14,865 +8,225 +3,002 +70.1 +% +NW Louisiana/E Texas: +Haynesville +— +16,984 +2,831 +1,033 +24.1 +% +Cotton Valley (3) +17 +3,498 +600 +219 +5.1 +% +Area Total +17 +20,482 +3,431 +1,252 +29.2 +% +Permian Basin: +SE New Mexico, West Texas +78 +36 +84 +31 +0.7 +% +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +5,843 +35,383 +11,740 +4,285 +100.0 +% +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(2) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 was an increase of 37% from our total oil equivalent production of approximately 4.3 million BOE for the year ended December 31, 2013 . This increased production was primarily due to our drilling operations in the Eagle Ford shale, as well as contributions from our initial wells in the Permian Basin. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, as compared to 11,740 BOE per day for the year ended December 31, 2013 . Our average daily oil production for the year ended December 31, 2014 was 9,095 Bbl of oil per day, an increase of 56% from 5,843 Bbl of oil per day for the year ended December 31, 2013 . Our average daily natural gas production for the year ended December 31, 2014 was 41.9 MMcf of natural gas per day, an increase of 18% from 35.4 MMcf of natural gas per day for the year ended December 31, 2013 . +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2014 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 93% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +South Texas: +Eagle Ford (1) +113 +95.2 +4 +4.0 +117 +99.2 +NW Louisiana/E Texas: +Haynesville +— +— +183 +16.8 +183 +16.8 +Cotton Valley (2) +2 +2.0 +95 +60.4 +97 +62.4 +Area Total +2 +2.0 +278 +77.2 +280 +79.2 +Permian Basin: +SE New Mexico, West Texas +26 +15.4 +5 +3.8 +31 +19.2 +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +— +Total +141 +112.6 +287 +85.0 +428 +197.6 +__________________ +16 +Table of Contents +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2014, 2013 and 2012 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Eagle Ford shale and the Permian Basin, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +At December 31, (1) +2014 +2013 +2012 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +24,184 +16,362 +10,485 +Natural Gas (Bcf) (3) +267.1 +212.2 +80.0 +Total (MBOE) (4) +68,693 +51,729 +23,819 +Estimated proved developed reserves: +Oil (MBbl) +14,053 +8,258 +4,764 +Natural Gas (Bcf) (3) +102.8 +53.5 +54.0 +Total (MBOE) (4) +31,185 +17,168 +13,771 +Percent developed +45.4 +% +33.2 +% +57.8 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +10,131 +8,104 +5,721 +Natural Gas (Bcf) (3) +164.3 +158.7 +26.0 +Total (MBOE) (4) +37,508 +34,561 +10,048 +PV-10 (5) (in millions) +$ +1,043.4 +$ +655.2 +$ +423.2 +Standardized Measure (6) (in millions) +$ +913.3 +$ +578.7 +$ +394.6 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.350 per MMBtu for natural gas, for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.670 per MMBtu for natural gas, and for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. +(3) +As a result of substantially lower natural gas prices in 2012, at June 30, 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves, most of which were attributable to non-operated properties. Primarily as a result of the continued improvement in natural gas prices during 2013, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2014 and 2013 . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2014, 2013 and 2012 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2014, 2013 and 2012 were, in millions, $130.1 , $76.5 and $28.6 , respectively. +17 +Table of Contents +(6) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +Our estimated total proved oil and natural gas reserves increase d 33% from 51.7 million BOE at December 31, 2013 to 68.7 million BOE at December 31, 2014 . Our proved oil reserves grew 48% from approximately 16.4 million Bbl at December 31, 2013 to approximately 24.2 million Bbl at December 31, 2014 . This increase is primarily attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas and our delineation and development operations in the Permian Basin. Our proved natural gas reserves increase d 26% from 212.2 Bcf at December 31, 2013 to 267.1 Bcf at December 31, 2014 . This increase in our proved natural gas reserves was attributable to our drilling and completion activities in 2014 and to Chesapeake’s drilling activities in the Haynesville shale on our Elm Grove properties that they operate. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf ( 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012. During 2013, primarily as a result of continued improvement in natural gas prices during the year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2014 and 2013 . The PV-10 of our total proved oil and natural gas reserves increase d 59% from $655.2 million at December 31, 2013 to $1.04 billion at December 31, 2014 . Our total proved reserves at December 31, 2014 were made up of approximately 35% oil and 65% natural gas, as compared to 32% oil and 68% natural gas at December 31, 2013 . +Our proved developed oil and natural gas reserves increase d 81% from 17.2 million BOE at December 31, 2013 to 31.2 million BOE at December 31, 2014 due primarily to our drilling programs in the Eagle Ford shale, our delineation and development operations in the Permian Basin and Chesapeake’s drilling activities in the Haynesville shale. Our proved developed oil reserves increase d 70% from 8.3 million Bbl at December 31, 2013 to 14.1 million Bbl at December 31, 2014 as a result of our drilling operations in the Eagle Ford shale and our delineation and development operations in the Permian Basin. Our proved developed natural gas reserves almost doubled from 53.5 Bcf at December 31, 2013 to 102.8 Bcf at December 31, 2014 due primarily to Chesapeake’s drilling activities in the Haynesville shale on our Elm Grove properties, which they operate. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2014 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2013 +17,168 +Extensions and discoveries +8,778 +Purchases of minerals-in-place +82 +Revisions of prior estimates +(196 +) +Production +(5,870 +) +Conversion of proved undeveloped to proved developed +11,223 +As of December 31, 2014 +31,185 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increased from 34.6 million BOE at December 31, 2013 to 37.5 million BOE at December 31, 2014 . Our proved undeveloped oil reserves increased from 8.1 million Bbl at December 31, 2013 to 10.1 million Bbl at December 31, 2014 , primarily as a result of our delineation and development operations in the Permian Basin. Our proved undeveloped natural gas reserves increased from 158.7 Bcf at December 31, 2013 to 164.3 Bcf at December 31, 2014 due primarily to our delineation and development operations in the Permian Basin and to wells drilled by our our co-working interest owners in the Haynesville shale. +At December 31, 2014 , we had no proved reserves in our estimates that remained undeveloped for five years or more following their booking. +18 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2014 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2013 +34,561 +Extensions and discoveries +15,143 +Purchases of minerals-in-place +— +Revisions of prior estimates +(973 +) +Conversion of proved undeveloped to proved developed +(11,223 +) +As of December 31, 2014 +37,508 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2012 , proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves Converted to Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2012 +283 +0.8 +415 +$ +8,096 +2013 +2,944 +8.3 +4,334 +115,699 +2014 +3,780 +44.7 +11,223 +201,950 +Total +7,007 +53.8 +15,972 +$ +325,745 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2014 : +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +PV-10 (2) +Standardized Measure (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +South Texas: +Eagle Ford (5) +16,106 +36.9 +22,257 +$ +603.8 +$ +528.5 +NW Louisiana/E Texas: +Haynesville +— +193.1 +32,183 +183.7 +160.8 +Cotton Valley (6) +26 +7.2 +1,223 +9.7 +8.5 +Area Total +26 +200.3 +33,406 +193.4 +169.3 +Permian Basin: +SE New Mexico, West Texas +8,052 +29.9 +13,030 +246.2 +215.5 +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +24,184 +267.1 +68,693 +$ +1,043.4 +$ +913.3 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2014 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2014 were approximately $ 130.1 million . +19 +Table of Contents +(3) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Vice President – Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 37 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. +20 +Table of Contents +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2014 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +South Texas: +Eagle Ford +23,835 +19,464 +16,036 +10,222 +39,871 +29,686 +NW Louisiana/E Texas: +Haynesville +17,605 +9,884 +3,690 +3,687 +21,295 +13,571 +Cotton Valley +18,776 +16,675 +3,586 +3,073 +22,362 +19,748 +Area Total (1) +22,895 +20,555 +4,356 +3,841 +27,251 +24,396 +Permian Basin: +SE New Mexico, West Texas +9,287 +7,109 +83,395 +58,967 +92,682 +66,076 +Other: +Wyoming, Utah, Idaho +1,600 +800 +74,074 +34,932 +75,674 +35,732 +Total +57,617 +47,928 +177,861 +107,962 +235,478 +155,890 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2014 that will expire prior to December 31, 2016 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. +Acres +Acres +Expiring 2015 +Expiring 2016 +Gross +Net +Gross +Net +South Texas: +Eagle Ford +1,607 +1,193 +2,631 +2,468 +NW Louisiana/E Texas: +Haynesville +— +— +839 +837 +Cotton Valley +— +— +80 +80 +Area Total (1) +— +— +839 +837 +Permian Basin: +SE New Mexico, West Texas (2) +5,875 +5,285 +32,918 +21,325 +Other: +Wyoming, Utah, Idaho +— +— +— +— +Total +7,482 +6,478 +36,388 +24,630 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +(2) +Approximately 60% of the acreage expiring in 2016 is associated with our Twin Lakes prospect in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2014 , our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. +21 +Table of Contents +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2014, 2013 and 2012 : +Year Ended December 31, +2014 +2013 +2012 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +89 +39.9 +32 +20.7 +36 +17.1 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +12 +10.6 +14 +8.7 +22 +10.4 +Dry (1) +— +— +1 +0.4 +— +— +Total Wells +Productive +101 +50.5 +46 +29.4 +58 +27.5 +Dry (1) +— +— +1 +0.4 +— +— +__________________ +(1) We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013. +Marketing +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the year ended December 31, 2014 , we had three significant purchasers that accounted for approximately 68% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2013 and 2012 , we had five and three significant purchasers that accounted for approximately 87% and 74% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +22 +Table of Contents +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, we had an immaterial natural gas deficiency and the counterparty to this agreement waived the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations. +Competition +The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas +23 +Table of Contents +Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. +Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue. +In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. +The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates +24 +Table of Contents +are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). +Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. +Environmental Regulation +The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the +25 +Table of Contents +OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. +26 +Table of Contents +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In December 2014, the EPA issued finalized additional amendments to these rules that, among other things, distinguished between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks permanently removed from service are not affected by any requirements. These rules have required changes to our operations, including the installation of new equipment to control emissions. We continue to evaluate the effect these rules have on our business and operations, which effects we do not expect to be material. Further, in 2012, seven states sued the EPA to compel the agency to make a determination as to whether setting standards of performance limiting methane emissions from oil and natural gas sources is appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and natural gas sources. In April 2014, the EPA released a set of five white papers analyzing methane emissions from the industry. In January 2015, EPA announced plans to issue a rule in summer 2015 governing methane emissions from the oil and natural gas industry. The Bureau of Land Management (BLM) is also expected to address methane emissions from the oil and natural gas industry on federal lands. These rules could increase our operating costs and have a material adverse effect on our business and operations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future international agreements, federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the +27 +Table of Contents +disposal of produced water. As of December 31, 2014 , we owned and operated five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows. +In addition, in some states and localities, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few state and local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. For example, in December 2014 New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. Voters in the city of Denton, Texas also recently approved a moratorium on hydraulic fracturing. These actions are the subject of legal challenges. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. +The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA recently issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, the EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released in December 2012, with draft final results expected in early 2015. Further, the BLM has proposed rules to regulate hydraulic fracturing on federal lands. The EPA has also announced an Advance Notice of Proposed Rulemaking under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, +have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and +28 +Table of Contents +similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K. Such information is incorporated herein by reference. +Employees +At December 31, 2014 , we had 99 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance +29 +Table of Contents +materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. \ No newline at end of file diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/item13.txt b/raw/filings/0001520006/2014/0001520006-15-000008/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8ea36dfefd8d51b5da312ba21694678384ff7d76 --- /dev/null +++ b/raw/filings/0001520006/2014/0001520006-15-000008/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. \ No newline at end of file diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/item9a.txt b/raw/filings/0001520006/2014/0001520006-15-000008/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ffe0cb4c5711354907aafbb7a788c71be49dd7ab --- /dev/null +++ b/raw/filings/0001520006/2014/0001520006-15-000008/item9a.txt @@ -0,0 +1,26 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2014 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2014 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +77 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2014 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of the Company and subsidiaries as of December 31, 2014 , and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the year then ended, and our report dated March 2, 2015 expressed an unqualified opinion on those consolidated financial statements. +/s/ KPMG LLP +Dallas, Texas +March 2, 2015 +78 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/rp_note.txt b/raw/filings/0001520006/2014/0001520006-15-000008/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2014/0001520006-15-000008/rpt_disclosure.txt b/raw/filings/0001520006/2014/0001520006-15-000008/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..a9c6506fb75e5a9cdb7608fafd6ca88bf7ddddbf --- /dev/null +++ b/raw/filings/0001520006/2014/0001520006-15-000008/rpt_disclosure.txt @@ -0,0 +1,57 @@ +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, since January 1, 2014, there has not been, nor is there currently proposed, any transaction or series of +similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the +immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive +Compensation—Compensation Discussion and Analysis” above. +George M. Yates was appointed to the Board on +April 28, 2015 and is a nominee for director at the Annual Meeting. Mr. Yates is Chairman and Chief Executive Officer of HEYCO Energy Group, Inc., an oil and natural gas exploration and production business based in Roswell, New Mexico +(“HEYCO”). HEYCO was the sole owner of Harvey E. Yates Company prior to the HEYCO Merger. While negotiating the HEYCO Merger, Matador was also negotiating the terms and conditions of proposed joint ventures (the “Joint Ventures”) +with three affiliates of HEYCO and/or Mr. Yates (the “HEYCO Affiliates”). In April 2015, Matador and the HEYCO Affiliates entered into non-binding letters of intent with respect to the Joint Ventures. The parties are currently +negotiating the terms of definitive agreements relating to the Joint Ventures. Pursuant to the Joint Ventures, a wholly-owned subsidiary of Matador would invest in two new entities with the HEYCO Affiliates for the purpose of developing certain +Delaware Basin properties in New Mexico. If we consummate the Joint Ventures, the Joint Ventures will result in Matador acquiring additional working interests in properties acquired by it in the HEYCO Merger. Mr. Yates is affiliated with each +of the HEYCO Affiliates and, therefore, following the closing of the transactions, the Joint Ventures will constitute related party transactions as defined in the Company’s Related Party Transaction Policy and applicable securities and stock +exchange rules. As presently negotiated, Matador’s collective investment in the Joint Ventures would equal approximately $14.2 million. +The Audit Committee has reviewed the terms of the Joint Ventures for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being fully informed as to +Mr. Yates’ relationship and interest and all other material facts related to the Joint Ventures, determined that the Joint Ventures were fair to the Company and recommended the Joint Ventures to the full Board for approval. The Board +subsequently approved such Joint Ventures. +In addition, in light of Mr. Yates’ ongoing services to HEYCO Energy +Group, Inc., the Board has, in accordance with Texas corporate law, adopted resolutions which renounce and provide for a waiver of certain corporate opportunities with respect to Mr. Yates. As a result, Mr. Yates will have no fiduciary +duty to present certain corporate opportunities related to Mr. Yates’ existing oil and gas holdings and/or in areas where Matador does not currently operate. +Procedures for Approval of Related Party Transactions +Our Board has +adopted a written related party transaction policy. Pursuant to this policy, a “Related Party Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or +guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, involving a Related Party (as defined below) and in which we are a participant, other than: +• +a transaction involving compensation of directors; +• +a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, change in control provision or +agreement or a special supplemental benefit for an executive officer; +• +a transaction available to all employees generally or to all salaried employees generally; +• +a transaction with a Related Party involving less than $120,000; +67 +Table of Contents +• +a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that +class receive the same benefit on a pro rata basis; or +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of +services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. +“Related Party” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or nominees for directors; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, +father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• +any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general +partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to our related party transaction policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or disapproval of the Related Party +Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all material facts of the Related Party +Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be disclosed in our filings with the SEC +and/or our website in accordance with applicable laws, rules and regulations. +68 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/filing.txt b/raw/filings/0001520006/2015/0001520006-16-000245/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..7f4ba9b433a5b9a67a099407b61668c17786d9fc --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/filing.txt @@ -0,0 +1,6448 @@ +10-K +1 +mtdr10-k12312015.htm +10-K +10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2015 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission file number 001-34574 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas +27-4662601 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 +Dallas, Texas 75240 +75240 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: (972) 371-5200 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ý No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +ý +Accelerated filer +¨ +Non-accelerated filer +¨ +(Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ¨ No ý +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,861,025,900 . +As of February 25, 2016 , there were 85,801,633 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2016 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +BUSINESS +2 +I TEM 1A. +RISK FACTORS +30 +I TEM 1B. +UNRESOLVED STAFF COMMENTS +49 +I TEM 2. +PROPERTIES +49 +I TEM 3. +LEGAL PROCEEDINGS +49 +I TEM 4. +MINE SAFETY DISCLOSURES +49 +PART II +I TEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +50 +I TEM 6. +SELECTED FINANCIAL DATA +53 +I TEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +55 +I TEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +74 +I TEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +75 +I TEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +75 +I TEM 9A. +CONTROLS AND PROCEDURES +75 +I TEM 9B. +OTHER INFORMATION +78 +PART III +I TEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +78 +I TEM 11. +EXECUTIVE COMPENSATION +78 +I TEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +78 +I TEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +78 +I TEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +78 +PART IV +I TEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +79 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should” or other similar words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, sufficient cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions, including the integration of Harvey E. Yates Company, with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report on Form 10-K and in other documents that we file with or furnish to the United States Securities and Exchange Commission, or the SEC, all of which are difficult to predict. Forward-looking statements may include statements about: +• +our business strategy; +• +our reserves; +• +our technology; +• +our cash flows and liquidity; +• +our financial strategy, budget, projections and operating results; +• +our oil and natural gas realized prices; +• +the timing and amount of future production of oil and natural gas; +• +the availability of drilling and production equipment; +• +the availability of oil field labor; +• +the amount, nature and timing of capital expenditures, including future exploration and development costs; +• +the availability and terms of capital; +• +our drilling of wells; +• +our ability to negotiate and consummate acquisition and divestiture opportunities; +• +government regulation and taxation of the oil and natural gas industry; +• +our marketing of oil and natural gas; +• +our exploitation projects or property acquisitions; +• +the integration of acquisitions, including the integration of Harvey E. Yates Company, with our business; +• +our ability to construct and operate midstream facilities; +• +our costs of exploiting and developing our properties and conducting other operations; +• +general economic conditions; +• +competition in the oil and natural gas industry; +• +the effectiveness of our risk management and hedging activities; +• +environmental liabilities; +• +counterparty credit risk; +• +developments in oil-producing and natural gas-producing countries; +• +our future operating results; +• +estimated future reserves and the present value thereof; and +• +our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty +1 +Table of Contents +as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report on Form 10-K, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities; +• maintain our financial discipline; and +• pursue opportunistic acquisitions and divestitures. +Despite a challenging commodity price environment in 2015, the successful execution of our business strategies led to significant increases in our oil and natural gas production and proved oil and natural gas reserves in 2015. We also significantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important transactions in 2015, including our merger with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., which added substantially to our Delaware Basin acreage position, our first issuance of senior unsecured notes, an equity offering and the sale of a portion of our midstream assets in Loving County, Texas to an affiliate of EnLink Midstream Partners, LP (“EnLink”). These transactions increased our operational flexibility and further strengthened our balance sheet. +2015 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2015 , we achieved record oil, natural gas and average daily oil equivalent production. In 2015 , we produced 4.5 million Bbl of oil, an increase of 35% , as compared to 3.3 million Bbl of oil produced in 2014. We also produced 27.7 Bcf of natural gas, an increase of 81% from 15.3 billion Bcf of natural gas produced in 2014. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, including 12,306 Bbl of oil per +2 +Table of Contents +day and 75.9 MMcf of natural gas per day, an increase of 55% , as compared to 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, for the year ended December 31, 2014 . The increase in oil production was primarily attributable to our ongoing delineation and development operations in the Delaware Basin throughout 2015, as well as our development activities in the Eagle Ford shale during early 2015 . The increase in natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production in our Elm Grove properties in Northwest Louisiana in the latter half of 2014 and throughout 2015, but also includes increased natural gas production associated with our operations in both the Delaware Basin and the Eagle Ford shale. Oil production comprised 49% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2015 , as compared to 57% for the year ended December 31, 2014 . +Increased Oil and Oil Equivalent Reserves +At December 31, 2015 , our estimated total proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, which is an increase of 24% from December 31, 2014 . The associated PV-10 of our estimated total proved oil and natural gas reserves decreased 48% to $541.6 million at December 31, 2015 from $1.04 billion at December 31, 2014 , as a result of declining oil and natural gas prices throughout 2015. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 89% to 45.6 million Bbl at December 31, 2015 from 24.2 million Bbl at December 31, 2014 . This growth in oil reserves was primarily attributable to our drilling program in the Delaware Basin during 2015 . Our proved natural gas reserves decreased 11% to 236.9 Bcf at December 31, 2015 from 267.1 Bcf at December 31, 2014 . This decrease in proved natural gas reserves was largely attributable to a decrease in our proved undeveloped natural gas reserves, principally from the reclassification of proved undeveloped natural gas reserves to contingent resources, primarily in the Haynesville shale, as a result of the decline in natural gas prices during 2015 as noted below in “— Estimated Proved Reserves.” As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by Matador or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +At December 31, 2015 , proved developed reserves included 17.1 million Bbl of oil and 101.4 Bcf of natural gas, and proved undeveloped reserves included 28.5 million Bbl of oil and 135.5 Bcf of natural gas. Proved developed reserves comprised 40% and proved oil reserves comprised 54% of our total proved oil and natural gas reserves, respectively, at December 31, 2015 . Proved developed reserves comprised 45% of our total reserves and proved oil reserves comprised 35% of our total proved oil and natural gas reserves, respectively, at December 31, 2014 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past two years, as we continued to apply there what we learned from our Eagle Ford shale, as well as from our Haynesville shale, experience. The Delaware Basin will continue to be our primary area of focus in 2016. +We completed and began producing oil and natural gas from 41 gross (25.0 net) wells in the Delaware Basin in 2015, including 27 gross (23.7 net) operated and 14 gross (1.3 net) non-operated wells. We also substantially increased our acreage position in the Delaware Basin during 2015. As a result, at December 31, 2015 our total acreage position in the Delaware Basin had increased to approximately 157,100 gross ( 88,800 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been very pleased with the initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our six main prospect areas in the Delaware Basin—the Wolf and Jackson Trust prospect areas in Loving County, Texas, the Rustler Breaks and Arrowhead prospect areas in Eddy County, New Mexico and the Ranger and Twin Lakes prospect areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin grew 3.6-fold from 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, in 2014 to an average daily oil equivalent production of 6,518 BOE per day, including 4,648 Bbl of oil per day and 11.2 MMcf of natural gas per day, in 2015 . We expect our Delaware Basin production to increase throughout 2016 as we continue the delineation and development of these properties. +During 2015 , we made significant progress in reducing drilling costs and times for both Wolfcamp and Bone Spring horizontal wells in the Delaware Basin. Our focus on improving drilling times and operational efficiencies has cut drilling +3 +Table of Contents +times by as much as 50% or more on recent Wolfcamp wells in the Wolf and Rustler Breaks prospect areas as compared to earlier wells drilled in those prospect areas. In the Wolf prospect area in Loving County, Texas, for example, Wolfcamp drilling times (spud to total depth) have been reduced from an average of 43 days in 2014 to as low as 18 days on a well drilled in late 2015. In the Rustler Breaks prospect area in Eddy County, New Mexico, where the Wolfcamp formation is shallower, Wolfcamp drilling times have been reduced from an average of 32 days in 2014 and early 2015 to as low as 15 days on recent wells drilled in late 2015. In addition, our most recent Second Bone Spring horizontal well in our Rustler Breaks prospect area was drilled from spud to total depth in 12 days, making it the fastest Second Bone Spring horizontal well we have drilled to date. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to our contracted drilling rigs, including 7,500-psi circulating systems, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and starting to drill wells in “batch” mode in some areas, particularly in the Wolf prospect area where we are in development mode. +These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, reduced overall well costs in 2015 . Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million, including production facilities and other related infrastructure. In the Rustler Breaks prospect area, we expect to drill and complete Wolfcamp wells for an average of $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure. Our most recent Second Bone Spring well in this area was drilled and completed for approximately $4.0 million on an existing multi-well pad, which is the least expensive Second Bone Spring well we have drilled thus far on our Delaware Basin acreage. These well costs are substantially reduced from those of initial wells drilled in these areas. We plan to continue to focus on improving operational efficiencies as we move closer to full development of our Delaware Basin assets. +We completed and began producing oil and natural gas from 18 gross (17.3 net) wells in the Eagle Ford shale in 2015, all in the early portion of the year, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well. During the second quarter of 2015, we concluded our drilling and completion operations in the Eagle Ford for 2015 and did not drill or complete any additional operated wells in the Eagle Ford shale for the remainder of 2015. +We did not drill any operated Haynesville shale wells during 2015, but we did participate in 22 gross (1.9 net) non-operated wells drilled in the Haynesville shale in Northwest Louisiana. The most impactful of these were the Haynesville wells drilled and completed by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove properties in southern Caddo Parish. In 2015, Chesapeake completed and placed on production nine gross (1.6 net) wells at Elm Grove. As a result of these 2015 completions and additional non-operated Haynesville wells completed and placed on production in the latter half of 2014, our Haynesville natural gas production grew 135% from 19.7 MMcf of natural gas per day in 2014 to 46.4 MMcf of natural gas per day in 2015. +Financing Arrangements +On April 14, 2015, we issued $400.0 million of 6.875% senior unsecured notes due 2023 in a private placement and, on October 21, 2015, we exchanged all of the privately placed senior notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act. On April 21, 2015, we completed a public offering of 7,000,000 shares of our common stock. After deducting offering costs totaling approximately $1.2 million , we received net proceeds of approximately $187.6 million . Finally, during the fourth quarter of 2015, the lenders party to our third amended and restated credit agreement (the “Credit Agreement”), under which we had no borrowings outstanding at December 31, 2015, reaffirmed our borrowing base at $375.0 million and extended the maturity date of the credit facility to October 16, 2020. See Note 6 to the consolidated financial statements in this Annual Report on Form 10-K for more details on each of the above items. +Acquisitions and Divestitures +On February 27, 2015, we completed a business combination pursuant to which one of our wholly-owned subsidiaries merged with HEYCO (the “HEYCO Merger”), combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico with our Delaware Basin operations. In the HEYCO Merger, we obtained approximately 58,600 gross ( 18,200 net) acres strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas. See Note 5 to the consolidated financial statements in this Annual Report on Form 10-K for more details on the HEYCO Merger. +We also acquired approximately 1,900 net acres contributed into two joint ventures with certain affiliates of HEYCO Energy Group, Inc. We have agreed to contribute an aggregate of approximately $14 million in exchange for a 50% interest in both entities. See Note 16 to the consolidated financial statements in this Annual Report on Form 10-K for more details on the joint ventures. +On October 1, 2015 , we completed the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County System”) to EnLink. The Loving County System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the +4 +Table of Contents +“Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects our gathering system to the Processing Plant. Pursuant to the terms of the transaction, EnLink paid cash consideration of approximately $143.4 million , excluding customary purchase price adjustments, and we dedicated our leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 5 and Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more details regarding the transaction with EnLink. +Principal Areas of Interest +Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. During 2015 , we devoted most of our efforts and most of our capital investment to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale in South Texas, although we completed our planned operated drilling and completion activities in the Eagle Ford shale for 2015 in the second quarter. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2015 , essentially all of our efforts were focused on unconventional plays. +At December 31, 2015 , our principal areas of interest consisted of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas, and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2015 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +157,133 +88,750 +256 +96.0 +3,543 +1,416.9 +47,124 +27.3 +6,518 +South Texas: +Eagle Ford (5) +39,035 +29,255 +134 +115.5 +260 +227.5 +19,015 +62.5 +10,263 +Northwest Louisiana/East Texas: +Haynesville +20,707 +13,007 +198 +18.4 +448 +109.2 +18,148 +46.3 +7,731 +Cotton Valley (6) +21,775 +19,185 +93 +58.4 +71 +50.1 +840 +100.0 +443 +Area Total (7) +26,663 +23,831 +291 +76.8 +519 +159.3 +18,988 +48.7 +8,174 +Other: +Wyoming, Utah, Idaho +75,674 +35,732 +— +— +— +— +— +— +— +Total +298,505 +177,568 +681 +288.3 +4,322 +1,803.7 +85,127 +40.0 +24,955 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2015 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2015 , these engineered drilling locations included only 118 gross (71.1 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Delaware Basin, 27 gross (26.8 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 26 gross (9.4 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formations at December 31, 2015 . +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplementary Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report on Form 10-K, which is incorporated herein by reference. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware and Avalon plays on our acreage in the Delaware Basin at December 31, 2015 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +5 +Table of Contents +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, Cimarex Energy Company, BHP Billiton, Mewbourne Oil Company, Occidental Petroleum Corporation, Chevron Corporation and others. At December 31, 2015 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2015 , we also were the operator for approximately 95% of our Eagle Ford acreage and approximately two-thirds of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are proven to be the source rocks for oil and natural gas produced in the basin. Historically, production has come from the “conventional” reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +We substantially increased our acreage position in the Delaware Basin during 2015, and as a result, at December 31, 2015 , our total acreage position in Southeast New Mexico and West Texas had increased to approximately 157,100 gross ( 88,800 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,100 gross (19,400 net) acres in our Ranger prospect area in Lea County, 47,400 gross (16,900 net) acres in our Arrowhead prospect area in Eddy County, 20,700 gross (13,400 net) acres in our Rustler Breaks prospect area in Eddy County, 12,200 gross (7,500 net) acres in our Wolf and Jackson Trust prospect areas in Loving County and 42,300 gross (29,900 net) acres in our Twin Lakes prospect area in Lea County at December 31, 2015 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2015 , our acreage position in the Delaware Basin was approximately 35% held by existing production, including substantially all of the acreage acquired in the HEYCO Merger. +During the year ended December 31, 2015 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 41 gross (25.0 net) wells in the Delaware Basin, including 27 gross (23.7 net) operated wells and 14 gross (1.3 net) non-operated wells, throughout our various prospect areas. At December 31, 2015 , we had tested a number of different producing horizons at various locations across our acreage position, +6 +Table of Contents +including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, two benches of the Wolfcamp B and the Wolfcamp D. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. +In our Wolf prospect area in Loving County, Texas, we made significant progress in reducing drilling costs and times for Wolfcamp horizontal wells during 2015 . Our focus on improving drilling times and operational efficiencies cut drilling times by as much as 58% on Wolfcamp wells drilled in late 2015 in the Wolf prospect area as compared to earlier wells drilled in this area. Wolfcamp drilling times (spud to total depth) were reduced from an average of 43 days in 2014 to as low as 18 days on a well drilled in late 2015. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to our contracted drilling rigs, including 7,500-psi circulating systems, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and drilling wells in “batch” mode in the Wolf prospect area where we are in development mode. These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, reduced overall well costs in the Wolf prospect area in 2015 . Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million in late 2015, including production facilities and related infrastructure costs. At December 31, 2015, we were conducting multi-well pad operations on two separate leases in our Wolf prospect area with one rig drilling a four-well horizontal stack on the Dick Jay pad and another rig drilling a three-well horizontal stack on our Dorothy White leasehold. +We continue to improve our fracture treatment design in the Delaware Basin. In the Wolf prospect area in late October 2015, we tested the use of a fracture stimulation diverting agent in one of our Billy Burt completions in the northwest portion of the Wolf prospect—the Billy Burt 90-TTT-B33 WF #201H. The Billy Burt 90-TTT-B33 WF #201H well was a Wolfcamp A-Y test and has a completed lateral length of 6,725 feet. The diverting agent was used in an effort to improve the efficiency of each fracturing stage and to ensure as many perforation clusters were treated as possible, while simultaneously improving well costs. Breakdown pressures monitored during the fracture treatments on the Billy Burt 90-TTT-B33 WF #201H well indicated that additional perforations were opened and new hydraulic fractures were created after the diverting agent was pumped in various stages of the fracturing operation. The Billy Burt 90-TTT-B33 WF #201H well initially tested about 1,100 BOE per day (68% oil), consisting of about 750 Bbl of oil per day and 2.1 MMcf of natural gas per day. More importantly, however, early production from the well over its initial 90 days was about 27% higher than the immediate 80-acre offsetting well having a similar lateral length, but where no diverting agent was used. We continue to refine and improve our fracture treatments designs, including the use of both existing technologies and new technologies as they become available and are determined to be beneficial, in an effort to improve the overall recovery from our Delaware Basin wells. +We made significant progress with our midstream operations in 2015 , particularly in the Wolf prospect area. As noted above in “—2015 Highlights—Acquisitions and Divestitures,” we completed the sale of the Loving County System to EnLink for cash proceeds of approximately $143.4 million, excluding customary purchase price adjustments, on October 1, 2015. At closing, the Processing Plant had been online for only about a month. Although we sold the Loving County System, we retained our infield natural gas gathering system up to a central delivery point and our other midstream assets in the Wolf prospect area, including oil and water gathering systems. We also retained our interest in a commercial salt water disposal facility in Loving County, operated by a joint venture controlled by the Company. During 2015 , the joint venture entity disposed of over 5.5 million barrels of salt water, with a total savings to the Company of approximately $6.5 million in salt water disposal costs. In addition, the joint venture entity began disposing of third-party salt water on a commercial basis in the fourth quarter of 2015. +We also made significant progress delineating and testing our acreage position in the Rustler Breaks prospect area in Eddy County, New Mexico in 2015. At December 31, 2014, we had drilled and completed only one well in Rustler Breaks—the Rustler Breaks 12-24S-27E RB #224H (formerly the Rustler Breaks 12-24-27 #1H)—in a single horizon of the Wolfcamp B. By the end of 2015, we had tested four different producing horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—across our Rustler Breaks prospect area from southeast to northwest. +One of the highlights and technical achievements of 2015 was the successful drilling and completion of our first three-zone stacked lateral test on a single drilling pad in the Rustler Breaks prospect area. From this single pad location, we successfully stacked three horizontal wells targeting three different horizons including, from shallowest to deepest, the Second Bone Spring, Wolfcamp A-XY and Wolfcamp B. The Wolfcamp B well (Tiger 14-24S-28E RB #224H) tested 1,533 BOE per day (42% oil), the Wolfcamp A-XY well (Tiger 14-24S-28E RB #204H) tested 1,405 BOE per day (75% oil) and the Second Bone Spring well (Tiger 14-24S-28E RB #124H) tested 702 BOE per day (83% oil). We were encouraged not only by the early results of this important technical advance, but also by the potential further savings that we anticipate can be achieved through the repeatability of this “stacked” pay concept at other locations. We expect to drill and complete Wolfcamp wells in the Rustler Breaks prospect area for an average of $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure, and our most recent Second Bone Spring well in this area was drilled and completed for approximately $4.0 million on an existing multi-well pad, which is the least expensive Second Bone Spring well we have drilled thus far on our Delaware Basin acreage. These well costs are substantially reduced from those of initial wells drilled in this area. +7 +Table of Contents +In mid-2015, the Scott Walker State 36-22S-27E RB #204H well, a Wolfcamp A-XY completion located in the far northwestern portion of our Rustler Breaks prospect area, was completed using our Generation 2 Wolfcamp fracture treatment design with 2,000 pounds of sand per foot of completed lateral and 30 barrels of fracturing fluid per foot of completed lateral. This well tested 504 BOE per day (70% oil), consisting of 354 Bbl of oil per day and 0.9 MMcf of natural gas per day. Although this well did not test at rates as high as our Wolfcamp A-XY tests in the southeastern part of the Rustler Breaks area—the Guitar 10-24S-28E RB #202H and Tiger 14-24S-28E RB #204H wells—we were encouraged by these results as they established the prospectivity of the Wolfcamp A-XY interval across our Rustler Breaks acreage position. To our knowledge, this is the northernmost horizontal test of the Wolfcamp A-XY to date in Eddy County, New Mexico. In late 2015, we tested the Wolfcamp A-XY close to the center of our Rustler Breaks acreage position using our Generation 3 fracture treatment design with up to 3,000 pounds of sand and 40 barrels of fracturing fluid per foot of completed lateral. This well, the Dr. K 24-23S-27E RB #203H, tested 1,241 BOE per day (69% oil), consisting of 856 Bbl of oil per day and 2.3 MMcf of natural gas per day during its 24-hour initial potential test, which further establishes the prospectivity of the Wolfcamp A-XY interval across our Rustler Breaks acreage position. Also, late in 2015, we completed and placed on production two additional wells from the multi-well pad referenced above. One of these wells was the Janie Conner 13-24S-28E RB #224H, a Wolfcamp B completion, which was also stimulated with increased sand concentrations up to 3,000 pounds of sand per foot of completed lateral. During its 24-hour initial potential test, this well flowed 1,703 BOE per day (59% oil), consisting of 1,005 Bbl of oil per day and 4.2 MMcf of natural gas per day, making it the best 24-hour initial potential test of any well we have drilled thus far in the Delaware Basin. +As noted above in “—2015 Highlights—Acquisitions and Divestitures,” in the HEYCO Merger we obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross ( 18,200 net) acres strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas. Most of the acreage from the HEYCO Merger is now included primarily in our Arrowhead prospect area in Eddy County, New Mexico and our Ranger prospect area in Lea County, New Mexico. We did not drill and complete any operated wells in our Arrowhead prospect area in 2015, but we did participate in several non-operated horizontal wells in the Arrowhead prospect area subsequent to the HEYCO Merger, which results illustrate the quality and prospectivity of our acreage in this area. We participated in, or acquired through the HEYCO Merger, four wells operated by an affiliate of Concho Resources Inc. in this area, the CTA State Com #3H, #4H, #5H and #6H wells. These wells were Second Bone Spring completions and tested at an average initial production rate of 956 BOE per day (85% oil). We own an approximate 15% working interest in each of these four wells. We also participated with Mewbourne Oil Company, Inc. in its Gobbler 5 B2PM #1H well in the Arrowhead prospect area. This well, a Second Bone Spring completion, tested 2,300 BOE per day (80% oil), and we own a 6% working interest in this well. +In the Ranger prospect area in Lea County, New Mexico, our first two Second Bone Spring completions have performed above our original projections for this area. As of January 2016, the Ranger State 33-20S-35E RN #121 (formerly the Ranger 33 State Com #1H) had produced 238,000 BOE (91% oil) in its first 26 months of production. The Pickard State 20-18S-34E RN #121H (formerly the Pickard State 20-18-34 #1H), also drilled and completed in the Second Bone Spring, had produced 205,000 BOE (89% oil) in its first 18 months of production. We installed gas-lift assist on the Ranger State 33-20S-35E RN #121 well within its first two months of production, and given the early success of the gas-lift assist on that well, the Pickard State 20-18S-34E RN #121H well was also equipped with gas-lift assist within approximately 30 days of being placed on production. The use of gas-lift assist on these wells in the Ranger prospect area is one example of a transfer of technology and lessons learned from our Eagle Ford shale development program in South Texas to the Delaware Basin. Also in the Ranger prospect area, we drilled and completed the Cimarron 16-19S-34E RN #134H well in the Third Bone Spring formation. During its 24-hour initial potential test, the Cimarron 16-19S-34E RN #134H well flowed 804 BOE per day (94% oil), consisting of 754 Bbl of oil per day and 303 Mcf of natural gas per day. Subsequent to this initial potential test, an electric submersible pump (“ESP”) was run in the well to enable it to continue to clean up and produce more efficiently. This was our first use of an ESP in one of our Ranger area wells. After installing the ESP, production from the Cimarron 16-19S-34E RN #134 well increased to over 1,100 BOE per day, and in its first 8.5 months of production as of January 2016, this well produced 123,000 BOE (94% oil). We consider this to be a strong test of the Third Bone Spring, which illustrates the potential for this interval of the Bone Spring as a viable completion target throughout the Ranger prospect area. During 2015, we also participated in a non-operated Second Bone Spring well offsetting our Pickard State 20-18S-34E RN #121H well. This well, the Iggles 21 State Com #1H, tested 1,300 BOE per day (90% oil), again confirming the prospectivity of the Second Bone Spring in our Ranger prospect area. +In our Twin Lakes prospect area in northern Lea County, New Mexico, we drilled a vertical pilot hole in the fourth quarter of 2015 where we gathered a full suite of openhole well logs and both whole core and rotary sidewall core samples in preparation for drilling our first horizontal well in the Twin Lakes area, which is currently planned for late 2016. At December 31, 2015 , we were evaluating the data collected from the vertical pilot hole and evaluating several horizons in the Wolfcamp D as potential horizontal landing targets. +8 +Table of Contents +As a result of our ongoing drilling and completion operations in these prospect areas, our Delaware Basin production increased significantly in 2015 . Our average daily oil equivalent production from the Delaware Basin increased 3.6-fold from 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, during 2014 to 6,518 BOE per day, including 4,648 Bbl of oil per day and 11.2 MMcf of natural gas per day, during 2015 . In addition, our average daily oil equivalent production from the Delaware Basin grew more than three-fold from 2,629 BOE per day in the fourth quarter of 2014 to 8,720 BOE per day in the fourth quarter of 2015 . For the year ended December 31, 2015 , 26% of our daily oil equivalent production was produced from the Delaware Basin. The Delaware Basin contributed approximately 38% of our daily oil production and approximately 15% of our daily natural gas production during 2015 , as compared to only approximately 14% of our daily oil production and approximately 7% of our daily natural gas production during 2014 . During the year ended December 31, 2014 , only approximately 11% of our daily oil equivalent production was attributable to the Delaware Basin. +At December 31, 2015 , approximately 56% of our estimated total proved oil and natural gas reserves, or 47.1 million BOE, was attributable to the Delaware Basin, including approximately 31.4 million Bbl of oil and 94.4 Bcf of natural gas, a 3.6-fold increase, as compared to 13.0 million BOE for the year ended December 31, 2014 . Our Delaware Basin proved reserves at December 31, 2015 comprised approximately 69% of our proved oil reserves and 40% of our proved natural gas reserves, as compared to approximately 33% of our proved oil reserves and 11% of our proved natural gas reserves at December 31, 2014 . The PV-10 of our proved reserves in the Delaware Basin at December 31, 2015 was $314.6 million , or approximately 58% of the PV-10 of our total proved reserves of $541.6 million . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +At December 31, 2015 , we had identified 3,543 gross ( 1,416.9 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Avalon and Delaware formations. These locations include 2,263 gross (1,284.1 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2015 do not yet include all portions of our acreage position, including the acreage associated with our Twin Lakes prospect area in Lea County, New Mexico. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2015 , these potential future drilling locations included only 118 gross (71.1 net) locations in the Delaware Basin to which we have assigned proved undeveloped reserves. +At December 31, 2015 and February 25, 2016 , we were operating three drilling rigs in the Delaware Basin—two in Loving County, Texas and one in Eddy County, New Mexico. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated approximately $315.0 million , or approximately 97% of our 2016 capital expenditure budget of $325.0 million , to our anticipated drilling, completion and midstream activities in the Delaware Basin, as well as for the acquisition of additional leasehold interests in the area. Our 2016 Delaware Basin drilling and completion program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of our Ranger and Arrowhead prospect areas. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2015 , our properties included approximately 39,000 gross ( 29,300 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 82% of our Eagle Ford acreage was held by production at December 31, 2015 , and approximately 92% of our Eagle Ford acreage +9 +Table of Contents +was either held by production at December 31, 2015 or not burdened by lease expirations before 2017 . In the third quarter of 2015, we acquired approximately 385 gross (385 net) acres in the Eagle Ford shale in Karnes County, Texas adjacent to our Sickenius prospect that we consider to be prospective primarily for oil. We plan to continue our leasing and acquisition efforts in the Eagle Ford shale as strategic opportunities are identified. +At January 1, 2015, we were operating two rigs in the Eagle Ford shale in South Texas, but as a result of both lower oil and natural gas prices in early 2015 and the fact that, at December 31, 2014, approximately 96% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2016, we suspended our operated Eagle Ford drilling and completion operations in the second quarter of 2015. +During the year ended December 31, 2015 , we completed and began producing oil and natural gas from 18 gross (17.3 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well, all in the first few months of 2015. During the second quarter of 2015, our Eagle Ford production increased to its all-time high of 11,942 BOE per day, including 9,358 Bbl of oil per day and 15.5 MMcf of natural gas per day. We completed our planned operated Eagle Ford drilling and completion operations for 2015 in the second quarter, and as a result, our Eagle Ford production declined during the second half of 2015. Despite conducting no operated activity for more than half of 2015, our average daily oil equivalent production from the Eagle Ford shale decreased only 2% from 10,501 BOE per day, including 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, during 2014 to 10,263 BOE per day, including 7,642 Bbl of oil per day and 15.7 MMcf of natural gas per day, during 2015 . For the year ended December 31, 2015 , 41% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2014 , approximately 65% of our daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2015 , approximately 22% of our estimated total proved oil and natural gas reserves, or 19.0 million BOE, was attributable to the Eagle Ford shale, including approximately 14.2 million Bbl of oil and 28.8 Bcf of natural gas. Our total proved reserves attributable to the Eagle Ford shale decreased approximately 15% to 19.0 million BOE for the year ended December 31, 2015 , as compared to 22.3 million BOE for the year ended December 31, 2014 , primarily as a result of declining oil and natural gas prices which resulted in certain previously classified Eagle Ford shale proved undeveloped reserves being reclassified to contingent resources at December 31, 2015. Our Eagle Ford total proved reserves at December 31, 2015 comprised approximately 31% of our proved oil reserves and 12% of our proved natural gas reserves, as compared to approximately 67% of our proved oil reserves and 14% of our proved natural gas reserves at December 31, 2014 . The PV-10 of our total proved reserves in the Eagle Ford shale was $175.1 million , or approximately 32% of the PV-10 of our total proved reserves of $541.6 million at December 31, 2015 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +We do not plan to drill any operated Eagle Ford shale wells in 2016 , but we have allocated approximately $5.6 million , or about 2% , of our 2016 estimated capital expenditure budget of $325.0 million to the Eagle Ford shale primarily to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, if desired. +At December 31, 2015 , we had identified 260 gross ( 227.5 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate the Eagle Ford wells to be drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. While we do not plan to drill any operated wells in the Eagle Ford in 2016, approximately 92% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2017 at December 31, 2015 . As a result, these engineered drilling locations remain available to be developed by us at a future time should commodity prices improve, drilling and completion costs decline further or new technologies be developed that increase the expected recoveries. At December 31, 2015 , these 260 gross ( 227.5 net) identified drilling locations included only 27 gross (26.8 net) locations to which we have assigned proved undeveloped reserves. +We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2015 , we had not drilled any Buda wells nor had we included any Buda locations in our future drilling locations. +10 +Table of Contents +Northwest Louisiana and East Texas +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2015 , although we did participate in the drilling and completion of 22 gross (1.9 net) non-operated Haynesville shale wells that were turned to sales in 2015 . These wells included nine gross (1.6 net) Haynesville wells operated by Chesapeake on our Elm Grove acreage in southern Caddo Parish, Louisiana. In addition, Chesapeake deferred first production until early January 2016 from an additional nine gross (1.9 net) wells drilled and completed in the latter half of 2015 on our Elm Grove acreage. We do not plan to drill any operated Haynesville shale wells in 2016 , but we have budgeted capital expenditures of approximately $4.4 million for our anticipated participation in five gross (0.6 net) Haynesville shale wells that we expect to be drilled or completed and placed on production by Chesapeake on certain of our non-operated properties, including Elm Grove, in 2016 . Certain of these wells were already in progress at December 31, 2015 . +At December 31, 2015 , we held approximately 26,700 gross ( 23,800 net) acres in Northwest Louisiana and East Texas, including 20,700 gross ( 13,000 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,700 gross ( 6,800 net) acres that we consider to be in the core area of the Haynesville play. +For the year ended December 31, 2015 , approximately 33% of our average daily oil equivalent production, or 8,174 BOE per day, including 16 Bbl of oil per day and 48.9 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 64% of our daily natural gas production, but oil production from these properties comprised only about 0.1% of our daily oil production during 2015 , as compared to approximately 54% of our daily natural gas production and approximately 0.2% of our daily oil production during 2014 . During the year ended December 31, 2014 , approximately 24% of our average daily oil equivalent production, or 3,791 BOE per day, including 17 Bbl of oil per day and 22.6 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2015 , approximately 61% of our daily natural gas production, or 46.4 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.6 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2014 , approximately 47% of our daily natural gas production, or 19.7 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 7% , or 2.9 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2015 , approximately 21% of our estimated total proved reserves, or 18.1 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 0.8 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2015 , we had identified and engineered 448 gross ( 109.2 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 448 gross ( 109.2 net) locations identified for future drilling on our Haynesville acreage, 373 gross (55.3 net) locations have been identified within the 13,700 gross ( 6,800 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2015 , these potential future drilling locations included only 26 gross (9.4 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Haynesville and Middle Bossier Shales +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. +11 +Table of Contents +At December 31, 2015 , we had approximately 20,700 gross ( 13,000 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,700 gross ( 6,800 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,200 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2015 . +Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%. +Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations +Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. +All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2015 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We have identified 71 gross ( 50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2015 and do not plan to drill any of these locations in 2016 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2015 , we held an estimated 11,700 gross (9,300 net) leasehold and mineral acres by existing production in these areas. +Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale +At December 31, 2015 , we held leasehold interests in approximately 75,700 gross ( 35,700 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort on this acreage. We are the operator of this prospect. We have drilled and completed one horizontal well on this acreage, but as of December 31, 2015 , we had not established commercial natural gas production on this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2015 . We have no plans to drill on this acreage in 2016 . +12 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production data for the years ended December 31, 2015, 2014 and 2013 . +Year Ended December 31, +2015 +2014 +2013 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +4,492 +3,320 +2,133 +Natural gas (Bcf) +27.7 +15.3 +12.9 +Total oil equivalent (MBOE) (1) +9,109 +5,870 +4,285 +Average daily production (BOE/d) (1) +24,955 +16,082 +11,740 +Average Sales Prices: +Oil, with realized derivatives (per Bbl) +$ +59.13 +$ +88.94 +$ +98.67 +Oil, without realized derivatives (per Bbl) +$ +45.27 +$ +87.37 +$ +99.79 +Natural gas, with realized derivatives (per Mcf) +$ +3.24 +$ +5.06 +$ +4.47 +Natural gas, without realized derivatives (per Mcf) +$ +2.71 +$ +5.08 +$ +4.35 +Operating Expenses (per BOE): +Production taxes and marketing +$ +3.90 +$ +5.65 +$ +4.89 +Lease operating +$ +6.39 +$ +8.75 +$ +9.04 +Depletion, depreciation and amortization +$ +19.63 +$ +22.95 +$ +22.96 +General and administrative +$ +5.50 +$ +5.48 +$ +4.85 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +1,697 +2,789 +— +6 +4,492 +Natural gas (Bcf) +4.1 +5.7 +16.9 +1.0 +27.7 +Total oil equivalent (MBOE) (3) +2,379 +3,746 +2,822 +162 +9,109 +Percentage of total annual net production +26.1 +% +41.1 +% +31.0 +% +1.8 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +4,648 +7,642 +— +16 +12,306 +Natural gas (MMcf/d) +11.2 +15.7 +46.4 +2.6 +75.9 +Total oil equivalent (BOE/d) +6,518 +10,263 +7,731 +443 +24,955 +Average Sales Price (4) +Oil (per Bbl) +$ +43.54 +$ +46.33 +$ +— +$ +43.68 +$ +45.27 +Natural gas (per Mcf) +$ +3.00 +$ +3.17 +$ +2.49 +$ +2.45 +$ +2.71 +Total oil equivalent (per BOE) +$ +36.21 +$ +39.35 +$ +14.97 +$ +15.69 +$ +30.56 +Production Costs (5) +Lease operating and marketing (per BOE) +$ +9.89 +$ +9.35 +$ +4.91 +$ +19.88 +$ +8.29 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes ad valorem taxes and oil and natural gas production taxes. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2014 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +480 +2,834 +— +6 +3,320 +Natural gas (Bcf) +1.0 +6.0 +7.2 +1.1 +15.3 +Total oil equivalent (MBOE) (3) +653 +3,833 +1,201 +183 +5,870 +Percentage of total annual net production +11.1 +% +65.3 +% +20.5 +% +3.1 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +1,314 +7,764 +— +17 +9,095 +Natural gas (MMcf/d) +2.9 +16.4 +19.7 +2.9 +41.9 +Total oil equivalent (BOE/d) +1,790 +10,501 +3,290 +501 +16,082 +Average Sales Price (4) +Oil (per Bbl) +$ +80.16 +$ +88.58 +$ +— +$ +91.24 +$ +87.37 +Natural gas (per Mcf) +$ +4.75 +$ +6.72 +$ +3.87 +$ +4.30 +$ +5.08 +Total oil equivalent (per BOE) +$ +66.41 +$ +75.99 +$ +23.27 +$ +27.92 +$ +62.64 +Production Costs (5) +Lease operating and marketing (per BOE) +$ +13.11 +$ +10.45 +$ +8.13 +$ +19.09 +$ +10.53 +_________________ +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2013 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +28 +2,098 +— +6 +2,132 +Natural gas (Bcf) +— +5.4 +6.2 +1.3 +12.9 +Total oil equivalent (MBOE) (3) +31 +3,002 +1,033 +219 +4,285 +Percentage of total annual net production +0.7 +% +70.1 +% +24.1 +% +5.1 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +78 +5,748 +— +17 +5,843 +Natural gas (MMcf/d) +— +14.9 +17.0 +3.5 +35.4 +Total oil equivalent (BOE/d) +84 +8,225 +2,831 +600 +11,740 +Average Sales Price (4) +Oil (per Bbl) +$ +90.71 +$ +99.91 +$ +— +$ +102.13 +$ +99.79 +Natural gas (per Mcf) +$ +5.27 +$ +6.03 +$ +3.05 +$ +3.55 +$ +4.35 +Total oil equivalent (per BOE) +$ +86.51 +$ +80.71 +$ +18.28 +$ +23.61 +$ +62.78 +Production Costs (5) +Lease operating and marketing (per BOE) +$ +15.68 +$ +11.65 +$ +5.24 +$ +15.39 +$ +10.30 +_________________ +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 increased 55% from our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 . This increased production was primarily due to our delineation and development operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, as compared to 16,082 BOE per day for the year ended December 31, 2014 . Our average daily oil production for the year ended December 31, 2015 was 12,306 Bbl of oil per day, an increase of 35% from 9,095 Bbl of oil per day for the year ended December 31, 2014 . Our average daily natural gas production for the year ended December 31, 2015 was 75.9 MMcf of natural gas per day, an increase of 81% from 41.9 MMcf of natural gas per day for the year ended December 31, 2014 . +Our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 increased 37% from our total oil equivalent production of approximately 4.3 million BOE for the year ended December 31, 2013 . This increased production was primarily due to our drilling and completion operations in the Eagle Ford shale, as well as contributions from our initial wells in the Delaware Basin. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, as compared to 11,740 BOE per day for the year ended December 31, 2013 . Our average daily oil production for the year ended December 31, 2014 was 9,095 Bbl of oil per day, an increase of 56% from 5,843 Bbl of oil per day for the year ended December 31, 2013 . Our average daily natural gas production for the year ended December 31, 2014 was 41.9 MMcf of natural gas per day, an increase of 18% from 35.4 MMcf of natural gas per day for the year ended December 31, 2013 . +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2015 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 69% in all wells that we operate at December 31, 2015, as compared to 93% at December 31, 2014, as a result of acquiring producing wells with lower working interests in the Delaware Basin as part of the HEYCO Merger in February 2015. For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +223 +84.9 +33 +11.1 +256 +96.0 +South Texas: +Eagle Ford (2) +130 +111.5 +4 +4.0 +134 +115.5 +Northwest Louisiana/East Texas: +Haynesville +— +— +198 +18.4 +198 +18.4 +Cotton Valley (3) +2 +2.0 +91 +56.4 +93 +58.4 +Area Total +2 +2.0 +289 +74.8 +291 +76.8 +Total +355 +198.4 +326 +89.9 +681 +288.3 +__________________ +(1) +Includes 175 gross (50.6 net) wells acquired in February 2015 as part of the HEYCO Merger. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2015, 2014 and 2013 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +16 +Table of Contents +At December 31, (1) +2015 +2014 +2013 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +45,644 +24,184 +16,362 +Natural Gas (Bcf) (3) +236.9 +267.1 +212.2 +Total (MBOE) (4) +85,127 +68,693 +51,729 +Estimated proved developed reserves: +Oil (MBbl) +17,129 +14,053 +8,258 +Natural Gas (Bcf) (3) +101.4 +102.8 +53.5 +Total (MBOE) (4) +34,037 +31,185 +17,168 +Percent developed +40.0 +% +45.4 +% +33.2 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +28,515 +10,131 +8,104 +Natural Gas (Bcf) (3) +135.5 +164.3 +158.7 +Total (MBOE) (4) +51,090 +37,508 +34,561 +PV-10 (5) (in millions) +$ +541.6 +$ +1,043.4 +$ +655.2 +Standardized Measure (6) (in millions) +$ +529.2 +$ +913.3 +$ +578.7 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas, and for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.67 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. +(3) +As a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves, most of which were attributable to non-operated properties in the Haynesville shale. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2015, 2014 and 2013 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015, 2014 and 2013 were, in millions, $12.4 , $130.1 and $76.5 , respectively. +(6) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +Our estimated total proved oil and natural gas reserves increase d 24% from 68.7 million BOE at December 31, 2014 to 85.1 million BOE at December 31, 2015 . We added 39.1 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2015, approximately 4.3 times our 2015 annual production of 9.1 million BOE. Our proved oil reserves grew 89% from approximately 24.2 million Bbl at December 31, 2014 to approximately 45.6 million Bbl at December 31, 2015 . This increase in proved oil reserves is primarily attributable to our drilling program in the Delaware Basin during 2015. Our proved natural gas reserves decrease d 11% from 267.1 Bcf at December 31, 2014 to 236.9 Bcf at December 31, 2015 . This decrease in proved natural gas reserves was primarily attributable to a decrease in our proved undeveloped natural gas reserves. As a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves, most of which were attributable to non-operated properties in the Haynesville shale. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +The PV-10 of our total proved oil and natural gas reserves decrease d 48% from $1.04 billion at December 31, 2014 to $541.6 million at December 31, 2015 , as a result of lower oil and natural gas prices. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2015 were $46.79 per Bbl and $2.59 per MMBtu, a decrease of 49% and 40%, respectively, as compared to average oil and natural gas prices of $91.48 per Bbl and $4.35 per MMBtu used to estimate proved reserves at December 31, 2014. Our total proved reserves at +17 +Table of Contents +December 31, 2015 were made up of approximately 54% oil and 46% natural gas, as compared to 35% oil and 65% natural gas at December 31, 2014 . +Our proved developed oil and natural gas reserves increase d 9% from 31.2 million BOE at December 31, 2014 to 34.0 million BOE at December 31, 2015 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 22% from 14.1 million Bbl at December 31, 2014 to 17.1 million Bbl at December 31, 2015 , also primarily as a result of our delineation and development operations in the Delaware Basin. Our proved developed natural gas reserves decreased 1% from 102.8 Bcf at December 31, 2014 to 101.4 Bcf at December 31, 2015 , resulting from downward revisions to certain of our proved developed natural gas reserves, primarily in the Haynesville shale, as a result of sharply lower natural gas prices in 2015, and to the 81% increase in our natural gas production to 27.7 Bcf in 2015 as compared to 15.3 Bcf in 2014. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2015 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2014 +31,185 +Extensions and discoveries +6,984 +Purchases of minerals-in-place +1,180 +Revisions of prior estimates +(2,950 +) +Production +(9,109 +) +Conversion of proved undeveloped to proved developed +6,747 +As of December 31, 2015 +34,037 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increased from 37.5 million BOE at December 31, 2014 to 51.1 million BOE at December 31, 2015 . Our proved undeveloped oil reserves increased from 10.1 million Bbl at December 31, 2014 to 28.5 million Bbl at December 31, 2015 , primarily as a result of our delineation and development operations in the Delaware Basin. Our proved undeveloped natural gas reserves decreased from 164.3 Bcf at December 31, 2014 to 135.5 Bcf at December 31, 2015 due primarily to the removal of previously classified proved undeveloped natural gas reserves from our total proved reserves, particularly in the Haynesville shale, as a result of lower natural gas prices in 2015, as noted above. +At December 31, 2015 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2015 within five years of booking these reserves. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2015 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2014 +37,508 +Extensions and discoveries +32,151 +Purchases of minerals-in-place +409 +Revisions of prior estimates +(12,231 +) +Conversion of proved undeveloped to proved developed +(6,747 +) +As of December 31, 2015 +51,090 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +The following table sets forth, since 2012, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves Converted to Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2012 +283 +0.8 +415 +$ +8,096 +2013 +2,944 +8.3 +4,334 +115,699 +2014 +3,780 +44.7 +11,223 +201,950 +2015 +2,854 +23.4 +6,747 +104,989 +Total +9,861 +77.2 +22,719 +$ +430,734 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2015 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +PV-10 (2) +Standardized Measure (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +31,395 +94.4 +47,124 +$ +314.6 +$ +307.4 +South Texas: +Eagle Ford (5) +14,221 +28.8 +19,015 +175.1 +171.1 +Northwest Louisiana/East Texas: +Haynesville +— +108.8 +18,148 +49.3 +48.2 +Cotton Valley (6) +28 +4.9 +840 +2.6 +2.5 +Area Total +28 +113.7 +18,988 +51.9 +50.7 +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +45,644 +236.9 +85,127 +$ +541.6 +$ +529.2 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2015 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015 were approximately $ 12.4 million . +(3) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational +19 +Table of Contents +methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 38 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2015 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +73,494 +30,814 +83,639 +57,936 +157,133 +88,750 +South Texas: +Eagle Ford +28,910 +23,431 +10,125 +5,824 +39,035 +29,255 +Northwest Louisiana/East Texas: +Haynesville +17,343 +9,644 +3,364 +3,363 +20,707 +13,007 +Cotton Valley +18,189 +16,111 +3,586 +3,074 +21,775 +19,185 +Area Total (1) +22,634 +20,315 +4,030 +3,517 +26,663 +23,831 +Other: +Wyoming, Utah, Idaho +1,600 +800 +74,074 +34,932 +75,674 +35,732 +Total +126,638 +75,360 +171,868 +102,209 +298,505 +177,568 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2015 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2019 and beyond represents an immaterial amount of our overall undeveloped acreage. +20 +Table of Contents +Acres +Acres +Acres +Expiring 2016 +Expiring 2017 +Expiring 2018 +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +34,235 +21,175 +17,188 +10,336 +18,045 +14,077 +South Texas: +Eagle Ford (2) +2,633 +2,435 +2,510 +2,484 +477 +477 +Northwest Louisiana/East Texas: +Haynesville +524 +523 +— +— +— +— +Cotton Valley +80 +80 +— +— +— +— +Area Total (3) +524 +523 +— +— +— +— +Other: +Wyoming, Utah, Idaho +— +— +21,874 +9,575 +48,859 +24,605 +Total +37,392 +24,133 +41,572 +22,395 +67,381 +39,159 +__________________ +(1) +Approximately 60% of the acreage expiring in 2016 is associated with our Twin Lakes prospect area in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes prospect area in 2016 through our 2016 drilling activities or by paying an additional lease bonus, where applicable. +(2) +We expect to extend portions of our expiring Eagle Ford acreage in 2016 by paying an additional lease bonus. +(3) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2015 , our leases are primarily fee and state leases with primary terms of three to five years. As a result of the HEYCO Merger in 2015, we also have acquired a significant number of federal leases with primary terms of 10 years; however, essentially all of the federal leases acquired in the HEYCO Merger are held by production. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2015, 2014 and 2013 . +Year Ended December 31, +2015 +2014 +2013 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +53 +26.7 +89 +39.9 +32 +20.7 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +28 +17.5 +12 +10.6 +14 +8.7 +Dry (1) +— +— +— +— +1 +0.4 +Total Wells +Productive +81 +44.2 +101 +50.5 +46 +29.4 +Dry (1) +— +— +— +— +1 +0.4 +__________________ +(1) We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013. +21 +Table of Contents +Marketing +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the year ended December 31, 2015 , we had three significant purchasers that accounted for approximately 59% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2014 and 2013 , we had three and five significant purchasers that accounted for approximately 68% and 87% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, we had an immaterial natural gas deficiency and the counterparty to this agreement waived the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” +As part of the sale of the Loving County System (See Note 5 to the consolidated financial statements in this Annual Report on Form 10-K), we entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby we committed to deliver the anticipated natural gas production from a significant portion of our Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facility. Under this agreement, if we do not meet the volume commitment for transportation and processing at the facility in a contract year, we will be required +22 +Table of Contents +to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, we can elect to have the previous year’s actual transportation and processing commitment be the new minimum commitment for each of the remaining years of the contract. As such, we have the ability to unilaterally reduce the transportation and processing commitment if our production in the Loving County area is less than our currently projected production. If we ceased operations in this area at December 31, 2015 , the total deficiency fee required to be paid would be approximately $9.6 million . In addition, if we elect to reduce the transportation and processing commitment in any year, we have the ability to elect to increase the committed volumes in any future year to the originally agreed transportation and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. We paid approximately $1.8 million in processing and transportation fees under this agreement during the year ended December 31, 2015 . We can elect to either sell the residue gas to the counterparty at the tailgate of its processing plant or have the counterparty deliver to us the residue gas in-kind to be sold to third parties downstream of the plant. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations. +Competition +The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” +23 +Table of Contents +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. +Texas, New Mexico, Louisiana, Wyoming, Idaho, Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue. +In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. +The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +24 +Table of Contents +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). +Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. +Environmental Regulation +The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. +25 +Table of Contents +We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil +26 +Table of Contents +and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Since January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. Further, in August 2015, the EPA issued proposed NSPS governing methane emissions from the oil and natural gas industry as well as proposed source determination standards for determining when oil and natural gas sources should be aggregated for CAA permitting and compliance purposes. The proposed NSPS for methane would extend the 2012 NSPS to remaining equipment and processes not currently regulated under the existing standards, including completions of hydraulically fractured oil wells, equipment leaks, pneumatic pumps and natural gas compressor station compressors. We continue to evaluate the effect these proposed rules would have on our business and operations. On January 22, 2016, the Department of the Interior proposed rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The proposed rules would, among other things, limit routine flaring of natural gas, require the payment of royalties on avoidable gas losses and require plans or programs relating to gas capture and leak detection and repair. The proposed rules are still in the period for public comment. These rules could increase our operating costs and have a material adverse effect on our business and operations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. In addition, ongoing international discussions are exploring options to succeed the Kyoto Protocol, most recently at the United Nations Conference on climate change in Paris in November-December 2015. These discussions could result in a legally binding international agreement to make certain global emissions reductions at a national level, which in turn could further drive regulation in the United States. Any future international agreements, federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, reporting of greenhouse gas emissions from onshore oil and natural gas production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2015 , we owned and operated nine underground injection wells and owned but did not operate two underground injection wells through a less-than-wholly-owned subsidiary, and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or +27 +Table of Contents +operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows. +In addition, some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. At the state level, Texas, New Mexico and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few state and local governments or regional authorities have imposed temporary moratoria on drilling permits. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing within city limits. These actions are the subject of legal challenges. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. +The EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, in June 2015, the EPA issued draft results of its study on the effects of hydraulic fracturing on drinking water resources. The EPA did not find evidence of widespread, systemic impacts on drinking water resources in the United States, although it did note a lack of data in many areas. Further, the BLM issued final rules to regulate hydraulic fracturing on federal lands in March 2015, although these rules have been temporarily stayed by the federal district court for the District of Wyoming pending litigation. The EPA has also announced an Advance Notice of Proposed Rulemaking under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, +have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +28 +Table of Contents +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2015 , we had 151 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary +29 +Table of Contents +at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +Item 1A. Risk Factors. +Risks Related to the Oil and Natural Gas Industry and Our Business +Our Success Is Dependent on the Prices of Oil and Natural Gas. Continued Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. +The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2015, the average price of oil was $48.79 per Bbl, ranging from a high of $61.43 per Bbl in mid-June to a low of $34.73 per Bbl in late December based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $2.63 per MMBtu, ranging from a high of $3.23 per MMBtu in mid-January to a low of $1.76 per MMBtu in mid-December based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Throughout 2015, oil and natural gas prices continued to decline sharply from their most recent highs in 2014. Oil prices have decreased 68% from $107.26 per Bbl in mid-June 2014 to $34.73 per Bbl in late December 2015, and natural gas prices have decreased 71% from $6.15 per MMBtu in mid-February 2014 to $1.76 per MMBtu in mid-December 2015. These sharp declines in oil and natural gas prices impacted our revenues, profitability and cash flows in 2015, as compared to 2014, and further declines in the prices of oil or natural gas could have an adverse impact on our borrowing capacity, ability to obtain additional capital, revenues, profitability and cash flows. +Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines caused us to recognize full-cost ceiling impairments in each quarter of 2015, and continued low prices may cause us to recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.” +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• +the domestic and foreign supply of, and demand for, oil and natural gas; +• +the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; +• +the prices and availability of competitors’ supplies of oil and natural gas; +• +the price and quantity of foreign imports; +• +the impact of U.S. dollar exchange rates on oil and natural gas prices; +• +domestic and foreign governmental regulations and taxes; +• +speculative trading of oil and natural gas futures contracts; +• +the availability, proximity and capacity of gathering, processing and transportation systems for natural gas; +• +the availability of refining capacity; +• +the prices and availability of alternative fuel sources; +• +weather conditions and natural disasters; +• +political conditions in or affecting oil and natural gas producing regions or countries, including the United States, Middle East, South America and Russia; +• +the continued threat of terrorism and the impact of military action and civil unrest; +30 +Table of Contents +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; +• +the level of global oil and natural gas inventories and exploration and production activity; +• +the impact of energy conservation efforts; +• +technological advances affecting energy consumption; and +• +overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain at economically unattractive levels for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. For example, if oil prices drop and remain below $30.00 per Bbl, we have the flexibility to reduce the number of rigs we are operating from three rigs to two rigs, either for a short time or for the remainder of 2016, beginning as early as the second quarter of 2016. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. +Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of oil and natural gas reserves. Our cash, operating cash flows and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +We may sell additional equity securities or issue additional debt securities to raise capital. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our estimated proved oil and natural gas reserves; +• +the amount of oil and natural gas we produce from existing wells; +• +the prices at which we sell our production; +• +the costs of developing and producing our oil and natural gas reserves; +• +our ability to acquire, locate and produce new reserves; +• +the ability and willingness of banks to lend to us; and +• +our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as further decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to +31 +Table of Contents +the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues continue to decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain exploration opportunities. Alternatively, to fund acquisitions, increase our rate of growth, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of midstream or other assets, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. +Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• +general economic and industry conditions, including the prices received for oil and natural gas; +• +shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• +potential drainage by operators on adjacent properties; +• +loss of or damage to oilfield development and service tools; +• +accidents, equipment failures or mechanical problems; +• +problems with title to the underlying properties; +• +increases in severance taxes; +• +adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• +domestic and foreign governmental regulations; and +• +proximity to and capacity of gathering, processing and transportation facilities. +Furthermore, our operations involve using some of the latest drilling and completion techniques developed by us and our service providers. For example, risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +• +landing our wellbore in the desired drilling zone; +• +staying in the desired drilling zone while drilling horizontally through the formation; +• +running our casing the entire length of the wellbore; +• +fracture stimulating the planned number of stages; and +32 +Table of Contents +• +being able to run tools and other equipment consistently through the horizontal wellbore. +If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +The Borrowing Base under Our Credit Agreement is Subject to Periodic Redetermination. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to factors beyond our control. As of February 25, 2016 , our borrowing base was $375.0 million , and we had no outstanding borrowings and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. At December 31, 2015, the PV-10 of our proved oil and natural gas reserves was $541.6 million , as compared to $1.04 billion at December 31, 2014. We could be required to repay a portion of our bank debt to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions. +Our Credit Agreement and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• +consolidate, merge or transfer all or substantially all of our assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. Continued low oil and natural gas prices or any further decline in the prices of oil or natural gas may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement or indenture is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +We May Not Be Able to Generate Sufficient Cash to Service All of Our Indebtedness and May Be Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May Not Be Successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our +33 +Table of Contents +ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We May Incur Additional Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. +At February 25, 2016 , we had available borrowings of approximately $374.4 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties, and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement) we may incur significant amounts of additional indebtedness, including under our Credit Agreement or through the issuance of additional notes, in order to fund acquisitions, develop our properties or invest in certain exploration opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• +requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• +increasing our vulnerability to general adverse economic and industry conditions; +• +placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• +restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• +increasing the risk that we may default on our debt obligations. +Our Credit Rating May be Downgraded Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations. +As of February 25, 2016 , our corporate credit rating from Standard & Poor’s Rating Services was “B” and our corporate credit rating from Moody’s Investors Service was “B2.” We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Similar to many of our competitors and other companies in the energy industry, in January 2016, our credit rating was placed under review by Moody’s Investors Service due to the possible effects of continued depressed oil and natural gas prices. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +34 +Table of Contents +Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including: +• +natural disasters; +• +adverse weather conditions; +• +loss of drilling fluid circulation; +• +blowouts where oil or natural gas flows uncontrolled at a wellhead; +• +cratering or collapse of the formation; +• +pipe or cement leaks, failures or casing collapses; +• +fires or explosions; +• +releases of hazardous substances or other waste materials that cause environmental damage; +• +pressures or irregularities in formations; and +• +equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana and East Texas. For the year ended December 31, 2015 , approximately 26% of our total oil and natural gas production, including approximately 38% of our average daily oil production, was attributable to our properties in the Delaware Basin and approximately 41% of our total oil and natural gas production, including approximately 62% of our average daily oil production, was attributable to our properties in the Eagle Ford shale. At December 31, 2015 , approximately 58% of the PV-10 of our total proved oil and natural gas reserves and approximately 69% of our total proved oil reserves were attributable to our properties in the Delaware Basin, and approximately 32% of the PV-10 of our total proved oil and natural gas reserves and approximately 31% of our total proved oil reserves were attributable to our properties in South Texas, primarily in the Eagle Ford shale. We expect that almost all of our operations in 2016 will be in the Delaware Basin. +The industry focus on the Delaware Basin and the Eagle Ford shale may adversely impact our ability to transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil and condensate trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. In connection with the sale of the Loving County System, in October 2015, we entered into a 15-year fixed-fee natural gas gathering and processing +35 +Table of Contents +agreement covering the anticipated natural gas production from a significant portion of our acreage in the Delaware Basin in West Texas. In addition, we have a firm natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, which expires in September 2017. However, due to the concentration of our operations we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, during the fourth quarters of 2014 and 2015, the Delaware Basin experienced severe winter weather that impacted many operators. In particular, the weather conditions and freezing temperatures resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In the third quarter of 2014, certain areas of the Delaware Basin experienced severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should low oil or natural gas prices continue or should oil and natural gas prices decline further, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the +36 +Table of Contents +extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the judgment of the persons preparing the estimate; and +• +the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves. +The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report on Form 10-K is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +actual costs and timing of development and production expenditures; +• +the amount and timing of actual production; and +• +changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most appropriate discount factor +37 +Table of Contents +based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 63% of Our Total Proved Reserves at December 31, 2015 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. +At December 31, 2015 , approximately 60% of our total proved reserves were undeveloped and approximately 3% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, the availability of equipment and capital, approval by regulators, lease terms and seasonal conditions. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. +At December 31, 2015 , we had leasehold interests in approximately 46,500 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2017 . Unless we establish production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third party leases may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic and geological data can be expensive to license or obtain and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid +38 +Table of Contents +for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. +Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected. +Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. +Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we will endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business, as well as certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue. +The unavailability of satisfactory oil, natural gas and natural gas liquids gathering, processing and transportation arrangements may hinder our access to oil, natural gas and natural gas liquids markets or delay production from our wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for, and supply of, oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas occasionally, which would decrease the volumes sold from our wells. +The disruption of third party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and natural gas liquids. The third parties control when or if such facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into a firm five-year natural gas processing and transportation agreement and a 15-year fixed-fee natural gas gathering and processing agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas and our Delaware Basin acreage in West Texas, respectively, +39 +Table of Contents +no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the thermal quantity transportation or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2016 . If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. +We derive most of our revenues from the sale of our oil, natural gas and natural gas liquids to unaffiliated third party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline further, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows. +Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. +The operations of the third parties on whom we rely for gathering, processing and transportation services, and, to a lesser extent, affiliate companies providing, or developing capacity to provide, such services, are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” +We Have Limited Control over Activities on Properties We Do Not Operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to Chesapeake in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• +timing and amount of capital expenditures; +• +the operator’s expertise and financial resources; +• +the rate of production of reserves, if any; +• +approval of other participants in drilling wells; and +• +selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, +40 +Table of Contents +and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. +In addition, we may be unable to successfully integrate any potential acquisitions into our existing operations. The inability to manage the integration of acquisitions, including the HEYCO Merger, effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our Credit Agreement and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. +Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. +If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired or other title deficiencies, our interest would be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. +It is not our practice in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease in all acquisitions. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be +41 +Table of Contents +significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows. +We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as they have been since the second half of 2014. In addition, non-cash write-downs may occur if we have: +• +downward adjustments to our estimated proved reserves; +• +increases in our estimates of development costs; or +• +deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. +Although uncertain future prices impact the ability to predict future full-cost ceiling impairments, we do anticipate recognizing full-cost ceiling impairments in 2016. This conclusion is based on the historic prices for 2015 and the first two months of 2016 as well as the short-term pricing outlook. For the year ended December 31, 2015, our net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an impairment charge of $801.2 million , exclusive of tax effect, to our net capitalized costs. For further discussion of the full-cost ceiling impairment at December 31, 2015, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Expenses.” A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and could lower the value of our common stock. +Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. As of February 25, 2016 , we had 44% and 44% of our estimated remaining 2016 oil and natural gas +42 +Table of Contents +production, respectively, hedged. We currently have no hedges in place for oil or natural gas liquids beyond 2016; however, we have a portion of our anticipated natural gas volumes hedged in 2017. +An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience with respect to our production. As such, we will be exposed to any increase in such differentials. +We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. In addition to expenditures required in order for us to comply with such laws and regulations, these expenditures could also include payments for: +• +personal injuries; +• +property damage; +• +containment and clean-up of oil and other spills; +• +management and disposal of hazardous materials; +• +remediation, clean-up costs and natural resource damages; and +• +other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as the lesser prairie-chicken and sand dune lizard in the Delaware Basin. The designation of previously unprotected species as threatened or endangered species could prohibit drilling in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production activities, each of which could have an adverse impact on our ability to develop and produce our reserves. +We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and +43 +Table of Contents +additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. +Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and natural gas liquids from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. The EPA released the draft results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in June 2015. The EPA did not find evidence of widespread, systemic impacts on drinking water resources in the United States, although it did note a lack of data in many areas. The results of the EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but did not pass, legislation to amend the Safe Drinking Water Act, or SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. The EPA has issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Additionally, the EPA has issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. Also at the federal level, the BLM issued final rules to regulate hydraulic fracturing on federal lands in March 2015, although these rules have been stayed by a federal court in Wyoming. +In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans/moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas, New Mexico and Wyoming have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. These restrictions and regulations could increase our costs of compliance and doing business. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. +The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, monitoring of greenhouse gas emissions from petroleum and natural gas systems commenced +44 +Table of Contents +on January 1, 2011, with the first annual reports required to be filed in 2012. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Finally, ongoing international discussions are exploring options to succeed the Kyoto Protocol, most recently at the United Nations Conference on climate change in Paris in November and December 2015. These discussions resulted in a non-binding international agreement to make certain global emissions reductions at a national level, which in turn could further drive regulation in the United States. Any future international agreements, federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. +On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Since January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. The finalized regulations also established specific requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. Further, in August 2015, the EPA issued proposed NSPS governing methane emissions from the oil and natural gas industry as well as proposed source determination standards for determining when oil and gas sources should be aggregated for CAA permitting and compliance purposes. The proposed NSPS for methane would extend the 2012 NSPS to remaining equipment and processes not currently regulated under the existing standards, including: completions of hydraulically fractured oil wells, equipment leaks, pneumatic pumps and natural gas compressors. We continue to evaluate the effect these rules would have on our business and operations. On January 22, 2016, the Department of the Interior proposed rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The proposed rules would, among other things, limit routine flaring of natural gas, require the payment of royalties on avoidable gas losses and require plans or programs relating to gas capture and leak detection and repair. The proposed rules are still in the period for public comment. These rules could increase our operating costs and have a material adverse effect on our business and operations. +A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. A change in the jurisdictional characterization by FERC, the courts or Congress or a change in policy by FERC or Congress may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +45 +Table of Contents +Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. The nature of our gathering facilities is such that we have not yet been regulated by FERC as a natural gas company subject to the provisions of the NGA. It is possible, however, that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. +On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished. +In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including any increase in oil exploration, development and production, and any increase in the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with +46 +Table of Contents +personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. Certain of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or Financial Loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion and production operations and data, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. +While we have not experienced any material losses due to cyber attacks, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to our proprietary information which could lead to data corruption, communication interruption, exposure of confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Risks Relating to Our Common Stock +The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2015 , our stock price fluctuated between a high of $29.90 and a low of $18.28 . In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• +our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• +quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• +changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• +speculation in the press or investment community; +• +announcement or consummation of acquisitions or dispositions by us; +• +public reaction to our press releases, announcements and filings with the SEC; +• +sales of our common stock by us or shareholders, or the perception that such sales may occur; +• +general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and natural gas liquids; +• +the realization of any of the risk factors presented in this Annual Report on Form 10-K; +47 +Table of Contents +• +the recruitment or departure of key personnel; +• +commencement of or involvement in litigation; +• +the success of our exploration and development operations, and the marketing of any oil, natural gas and natural gas liquids we produce; +• +changes in market valuations of companies similar to ours; and +• +domestic and international economic, legal and regulatory factors unrelated to our performance. +If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and occupies a significant amount of time of our Board of Directors and management and has significantly increased our costs and expenses. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal controls over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Further, our remediation efforts may not enable us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. +We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. +Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• +authorization for our Board of Directors to issue preferred stock without shareholder approval; +• +a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +48 +Table of Contents +• +the prohibition of cumulative voting in the election of directors; and +• +a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +Our Directors and Executive Officers Own a Significant Percentage of Our Equity, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. +As of February 25, 2016 , our directors and executive officers beneficially owned approximately 14% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the company, even if that change of control might benefit our shareholders. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are a defendant in several lawsuits encountered in the ordinary course of our business. While the ultimate outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on our financial condition, results of operations or cash flows. +Item 4. Mine Safety Disclosures. +Not applicable. +49 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 25, 2016 , we had 85,801,633 shares of common stock outstanding held by approximately 340 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated. +2015 +2014 +High +Low +High +Low +First Quarter +$ +25.08 +$ +18.28 +$ +25.84 +$ +17.95 +Second Quarter +$ +29.90 +$ +22.01 +$ +29.36 +$ +23.28 +Third Quarter +$ +26.07 +$ +19.08 +$ +29.94 +$ +23.70 +Fourth Quarter +$ +28.25 +$ +18.87 +$ +26.09 +$ +14.08 +On February 25, 2016 , the last reported sales price of our common stock on the NYSE was $15.93 per share. +Dividend Policy +We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends on our common stock. During the years ended December 31, 2015 and 2014 , we did not pay dividends to holders of our common stock. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2015 . +Equity Compensation Plan Information +Plan Category +Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights +Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights +Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1) (2) +2,436,784 +$ +15.40 +5,066,503 +Equity compensation plans not approved by security holders +— +— +— +Total +2,436,784 +$ +15.40 +5,066,503 +__________________ +(1) +Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. +(2) +The Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015 and approved by our shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8 to the consolidated financial statements in this Annual Report on Form 10-K. +50 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from February 2, 2012, the date our common stock began trading on the NYSE, through December 31, 2015 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +51 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2015, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs +Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2015 to October 31, 2015 +674 +$ +27.48 +— +— +November 1, 2015 to November 30, 2015 +912 +26.35 +— +— +December 1, 2015 to December 31, 2015 +— +— +— +— +Total +1,586 +$ +26.83 +— +— +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. +52 +Table of Contents +Item 6. Selected Financial Data. +You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K. The financial information included in this Annual Report on Form 10-K may not be indicative of our future results of operations, financial condition or cash flows. +The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2015 and selected consolidated balance sheet and cash flow data at December 31, 2015 , 2014 , 2013 , 2012 and 2011 and should be read in conjunction with the consolidated financial statements for the years ended December 31, 2015, 2014 and 2013 included herewith. +Year Ended December 31, +2015 +2014 +2013 +2012 +2011 +(In thousands, except per share data) +Statement of operations data: +Revenues +Oil and natural gas revenues +$ +278,340 +$ +367,712 +$ +269,030 +$ +155,998 +$ +67,000 +Realized gain (loss) on derivatives +77,094 +5,022 +(909 +) +13,960 +7,106 +Unrealized (loss) gain on derivatives +(39,265 +) +58,302 +(7,232 +) +(4,802 +) +5,138 +Total revenues +316,169 +431,036 +260,889 +165,156 +79,244 +Expenses +Production taxes and marketing +35,535 +33,172 +20,973 +11,672 +6,278 +Lease operating +58,193 +51,353 +38,720 +28,184 +7,244 +Depletion, depreciation and amortization +178,847 +134,737 +98,395 +80,454 +31,754 +Accretion of asset retirement obligations +734 +504 +348 +256 +209 +Full-cost ceiling impairment +801,166 +— +21,229 +63,475 +35,673 +General and administrative +50,105 +32,152 +20,779 +14,543 +13,394 +Total expenses +1,124,580 +251,918 +200,444 +198,584 +94,552 +Operating (loss) income +(808,411 +) +179,118 +60,445 +(33,428 +) +(15,308 +) +Other income (expense): +Net gain (loss) on asset sales and inventory impairment +908 +— +(192 +) +(485 +) +(154 +) +Interest expense +(21,754 +) +(5,334 +) +(5,687 +) +(1,002 +) +(683 +) +Interest and other income +2,365 +1,345 +225 +224 +315 +Total other (expense) income +(18,481 +) +(3,989 +) +(5,654 +) +(1,263 +) +(522 +) +Net (loss) income +(679,524 +) +110,754 +45,094 +(33,261 +) +(10,309 +) +Net (income) loss attributable to non-controlling interest in subsidiaries +(261 +) +17 +— +— +— +Net (loss) income attributable to +Matador Resources Company shareholders +$ +(679,785 +) +$ +110,771 +$ +45,094 +$ +(33,261 +) +$ +(10,309 +) +Earnings (loss) per common share +Basic +Class A (1) +$ +(8.34 +) +$ +1.58 +$ +0.77 +$ +(0.62 +) +$ +(0.25 +) +Class B (1) +$ +— +$ +— +$ +— +$ +(0.35 +) +$ +0.02 +Diluted +Class A (1) +$ +(8.34 +) +$ +1.56 +$ +0.77 +$ +(0.62 +) +$ +(0.25 +) +Class B (1) +$ +— +$ +— +$ +— +$ +(0.35 +) +$ +0.02 +Class B dividend declared, per share (1) +$ +— +$ +— +$ +— +$ +0.27 +$ +0.27 +__________________ +(1) +Our Class B common stock converted into Class A common stock upon the consummation of our initial public offering on February 7, 2012 and the Class A common stock then became the only class of common stock authorized. The term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering. +53 +Table of Contents +At December 31, +2015 +2014 +2013 +2012 +2011 +(In thousands) +Balance sheet data: +Cash and cash equivalents +$ +16,732 +$ +8,407 +$ +6,287 +$ +2,095 +$ +10,284 +Restricted cash +44,357 +609 +— +— +— +Certificates of deposit +— +— +— +230 +1,335 +Net property and equipment +1,012,406 +1,322,072 +845,877 +591,090 +399,865 +Total assets +1,140,861 +1,434,490 +890,330 +632,029 +439,469 +Current liabilities +136,830 +142,036 +100,327 +96,492 +74,576 +Long-term liabilities +515,072 +425,913 +221,079 +156,433 +93,378 +Total Matador Resources Company shareholders’ equity +$ +488,003 +$ +866,408 +$ +568,924 +$ +379,104 +$ +271,515 +Year Ended December 31, +2015 +2014 +2013 +2012 +2011 +(In thousands) +Other financial data: +Net cash provided by operating activities +$ +208,535 +$ +251,481 +$ +179,470 +$ +124,228 +$ +61,868 +Net cash used in investing activities +(425,154 +) +(570,531 +) +(366,939 +) +(306,916 +) +(160,088 +) +Oil and natural gas properties capital expenditures +(432,715 +) +(560,849 +) +(363,192 +) +(300,689 +) +(156,431 +) +Expenditures for other property and equipment +(64,499 +) +(9,152 +) +(3,977 +) +(7,332 +) +(4,671 +) +Net cash provided by financing activities +224,944 +321,170 +191,661 +174,499 +87,444 +Adjusted EBITDA (1) +$ +223,155 +$ +262,943 +$ +191,771 +$ +115,923 +$ +49,911 +__________________ +(1) +Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “ – Non-GAAP Financial Measures” below. +Non-GAAP Financial Measures +We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +54 +Table of Contents +Year Ended December 31, +2015 +2014 +2013 +2012 +2011 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net (Loss) Income: +Net (loss) income attributable to Matador Resources Company shareholders +$ +(679,785 +) +$ +110,771 +$ +45,094 +$ +(33,261 +) +$ +(10,309 +) +Interest expense +21,754 +5,334 +5,687 +1,002 +683 +Total income tax (benefit) provision +(147,368 +) +64,375 +9,697 +(1,430 +) +(5,521 +) +Depletion, depreciation and amortization +178,847 +134,737 +98,395 +80,454 +31,754 +Accretion of asset retirement obligations +734 +504 +348 +256 +209 +Full-cost ceiling impairment +801,166 +— +21,229 +63,475 +35,673 +Unrealized loss (gain) on derivatives +39,265 +(58,302 +) +7,232 +4,802 +(5,138 +) +Stock-based compensation expense +9,450 +5,524 +3,897 +140 +2,406 +Net (gain) loss on asset sales and inventory impairment +(908 +) +— +192 +485 +154 +Adjusted EBITDA +$ +223,155 +$ +262,943 +$ +191,771 +$ +115,923 +$ +49,911 +Year Ended December 31, +2015 +2014 +2013 +2012 +2011 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities +$ +208,535 +$ +251,481 +$ +179,470 +$ +124,228 +$ +61,868 +Net change in operating assets and liabilities +(8,980 +) +5,978 +6,210 +(9,307 +) +(12,594 +) +Interest expense, net of non-cash portion +20,902 +5,334 +5,687 +1,002 +683 +Current income tax provision (benefit) +2,959 +133 +404 +— +(46 +) +Net (income) loss attributable to non-controlling interest in subsidiaries +(261 +) +17 +— +— +— +Adjusted EBITDA +$ +223,155 +$ +262,943 +$ +191,771 +$ +115,923 +$ +49,911 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +Overview +We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +2015 Operational Highlights +During the year ended December 31, 2015 , we completed and began producing oil and natural gas from 27 gross (23.7 net) operated and 14 gross (1.3 net) non-operated wells in the Delaware Basin. Although we suspended our Eagle Ford drilling and completion operations in the second quarter of 2015, we also completed and began producing oil and natural gas from 17 gross (17.0 net) operated and one gross (0.3 net) non-operated Eagle Ford shale wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2015, although we did +55 +Table of Contents +participate in the drilling and completion of 22 gross (1.9 net) non-operated Haynesville shale wells that were turned to sales in 2015. +At January 1, 2015, we were operating five contracted drilling rigs two rigs in the Eagle Ford shale in South Texas and three rigs in the Delaware Basin in Southeast New Mexico and West Texas, but we reduced our operated drilling rigs to two by the end of the first quarter of 2015 with both rigs operating in the Delaware Basin. In late July 2015, we took delivery of a third state-of-the-art, new-build drilling rig in the Delaware Basin specifically customized to our specifications. Overall, we have been very pleased with the initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our six main prospect areas in the Delaware Basin—the Wolf and Jackson Trust prospect areas in Loving County, Texas, the Rustler Breaks and Arrowhead prospect areas in Eddy County, New Mexico and the Ranger and Twin Lakes prospect areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Approximately 78% of our 2015 capital expenditures of $482.1 million (excluding capital expenditures associated with the HEYCO Merger) were directed to the delineation and development of our leasehold position in the Delaware Basin, to the development of certain midstream assets to support our operations there, and to the acquisition of additional leasehold interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. The remaining 22% of our capital expenditures (excluding capital expenditures associated with the HEYCO Merger) were directed to our operated drilling and completion activities in the Eagle Ford shale in the early part of 2015 and to our participation in a number of non-operated wells drilled and completed in the Haynesville shale throughout 2015, as noted above. +We increased our leasehold position significantly in the Delaware Basin during 2015. At December 31, 2014 , we held approximately 92,700 gross (66,100 net) acres in Southeast New Mexico and West Texas. Including the acreage added as part of the HEYCO Merger and other transactions completed during 2015, at December 31, 2015 , our total acreage position in this area had increased to 157,100 gross ( 88,800 net) acres, primarily in the Delaware Basin in Loving County, Texas and Lea and Eddy Counties, New Mexico. +Our oil production, natural gas production and average daily oil equivalent production during 2015 were the best in Matador’s history. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, an increase of 55% as compared to 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, for the year ended December 31, 2014 . Our average daily oil production in 2015 of 12,306 Bbl of oil per day increased 35% , as compared to an average daily oil production of 9,095 Bbl of oil per day in 2014 . This increase in oil production was primarily a result of increased oil production from newly drilled and completed wells in the Delaware Basin, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily natural gas production of 75.9 MMcf per day for the year ended December 31, 2015 increased 81% from 41.9 MMcf per day for the year ended December 31, 2014 . This increase in natural gas production is primarily attributable to new, non-operated Haynesville shale wells completed and placed on production by Chesapeake on our Elm Grove properties in Northwest Louisiana in the latter half of 2014 and throughout 2015, but also includes increased natural gas production associated with our operations in both the Delaware Basin and the Eagle Ford shale. Oil production comprised 49% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2015 , as compared to 57% for the year ended December 31, 2014 . +For the year ended December 31, 2015 , our oil and natural gas revenues were $278.3 million , a decrease of 24% from oil and natural gas revenues of $367.7 million for the year ended December 31, 2014 . Our oil revenues and natural gas revenues decreased 30% and 3% to approximately $203.4 million and $75.0 million , respectively, as a result of significantly lower oil and natural gas prices realized for the year ended December 31, 2015 , as compared to $290.0 million and $77.7 million , respectively, for the year ended December 31, 2014 . Adjusted EBITDA for the year ended December 31, 2015 was $223.2 million , a decrease of 15% from Adjusted EBITDA of $262.9 million reported for the year ended December 31, 2014 . Our Adjusted EBITDA of $223.2 million for the year ended December 31, 2015 was the second best Adjusted EBITDA result in Matador’s history, surpassed only by record Adjusted EBITDA of $262.9 million reported for 2014. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +At December 31, 2015 , our estimated total proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, with a PV-10 of $541.6 million and a Standardized Measure of $529.2 million . At December 31, 2014 , our estimated proved oil and natural gas reserves were 68.7 million BOE, including 24.2 million Bbl of oil and 267.1 Bcf of natural gas, with a PV-10 of $1.04 billion and a Standardized Measure of $913.3 million . Our estimated total proved reserves of 85.1 million BOE at December 31, 2015 represented a 24% year-over-year increase, as compared to 68.7 million BOE at December 31, 2014 . Our estimated proved oil reserves of 45.6 million Bbl at December 31, 2015 increased 89% , as compared to 24.2 million Bbl at December 31, 2014 . Our proved oil reserves in the Delaware Basin increased almost four-fold to 31.4 million Bbl at December 31, 2015 , as compared to 8.1 million Bbl at December 31, 2014 , resulting from our ongoing delineation and development operations in the Delaware Basin. Proved oil reserves comprised 54% +56 +Table of Contents +of our total proved reserves at December 31, 2015 , as compared to 35% at December 31, 2014 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” +2016 Capital Expenditure Budget +In response to the continued decline in oil and natural gas prices experienced throughout 2015 and into early 2016 , we have reduced our 2016 estimated capital expenditure budget to $325.0 million , a decrease of 33%, as compared to actual capital expenditures of $482.1 million (excluding capital expenditures associated with the HEYCO Merger) for the year ended December 31, 2015 . We plan to operate three contracted drilling rigs in the Delaware Basin throughout 2016 , although should oil prices drop and remain below $30.00 per Bbl, we have the flexibility to reduce the number of rigs we are operating from three rigs to two rigs, either for a short time or for the remainder of 2016 , beginning as early as the second quarter of 2016. This could reduce our estimated 2016 capital expenditures by approximately $50.0 million. Our 2016 estimated capital expenditure budget of $325.0 million (assuming a three-rig program) consists of approximately $260.0 million for drilling, completions, facilities and infrastructure, $40.0 million principally for the completion of new midstream facilities in the Delaware Basin to support our operations there and $25.0 million for land acquisitions and seismic data, primarily in the Delaware Basin. Development of our Delaware Basin assets will be the primary driver of our projected growth in 2016 . Approximately $315.0 million , or 97% , of our 2016 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position in the Delaware Basin. Our 2016 Delaware Basin drilling program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of the Ranger and Arrowhead prospect areas. The $40.0 million in midstream capital expenditures is expected to primarily fund completion of the construction and installation of a cryogenic natural gas processing plant with approximately 60 MMcf per day of inlet capacity and a natural gas gathering system in the Rustler Breaks prospect area in Eddy County, New Mexico. This plant is expected to be operational by the third quarter of 2016. +We do not plan to drill any operated Eagle Ford shale wells in South Texas or Haynesville shale wells in Northwest Louisiana and East Texas during 2016 . Approximately $5.6 million , or 2% , of our 2016 estimated capital expenditures will be allocated to the Eagle Ford shale to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, if desired, and approximately $4.4 million , or just over 1% , of our 2016 estimated capital expenditures will be allocated to participation in non-operated Haynesville shale wells. Approximately 92% of our Eagle Ford acreage and essentially all of our Haynesville and Cotton Valley acreage was either held by production at December 31, 2015 or not burdened by lease expirations before 2017 . +At December 31, 2015 , we had $61.1 million in cash (including restricted cash) and $374.4 million in undrawn borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit). As a result, we expect to fund our 2016 drilling program through a combination of operating cash flows and borrowings under our Credit Agreement (assuming availability under our borrowing base). We may also consider funding a portion of our 2016 capital expenditures through additional credit arrangements, potential joint ventures, the sale of midstream or other assets or acreage and the potential issuance of equity, debt or convertible securities, none of which may be available. While we have budgeted approximately $325.0 million of capital expenditures for 2016 , the aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs of our midstream activities, other opportunities that may become available to us and our ability to obtain capital. +57 +Table of Contents +Revenues +Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices. +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2015 +2014 +2013 +Operating Data: +Revenues (in thousands): (1) +Oil +$ +203,355 +$ +290,026 +$ +212,833 +Natural gas +74,985 +77,686 +56,197 +Total oil and natural gas revenues +278,340 +367,712 +269,030 +Realized gain (loss) on derivatives +77,094 +5,022 +(909 +) +Unrealized (loss) gain on derivatives +(39,265 +) +58,302 +(7,232 +) +Total revenues +$ +316,169 +$ +431,036 +$ +260,889 +Net Production Volumes: (1) +Oil (MBbl) +4,492 +3,320 +2,133 +Natural gas (Bcf) +27.7 +15.3 +12.9 +Total oil equivalent (MBOE) (2) +9,109 +5,870 +4,285 +Average daily production (BOE/d) (2) +24,955 +16,082 +11,740 +Average Sales Prices: +Oil, with realized derivatives (per Bbl) +$ +59.13 +$ +88.94 +$ +98.67 +Oil, without realized derivatives (per Bbl) +$ +45.27 +$ +87.37 +$ +99.79 +Natural gas, with realized derivatives (per Mcf) +$ +3.24 +$ +5.06 +$ +4.47 +Natural gas, without realized derivatives (per Mcf) +$ +2.71 +$ +5.08 +$ +4.35 +________________ +(1) +We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues. +(2) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014 +Oil and natural gas revenues . Our oil and natural gas revenues decrease d $89.4 million to $278.3 million , or a decrease of 24% for the year ended December 31, 2015 , as compared to $367.7 million for the year ended December 31, 2014 . Our oil revenues decrease d $86.7 million , a decrease of 30% , to $203.4 million for the year ended December 31, 2015 , as compared to $290.0 million for the year ended December 31, 2014 . The decrease in oil revenues resulted from a significantly lower weighted average oil price realized for the year ended December 31, 2015 of $45.27 per Bbl, as compared to $87.37 per Bbl realized for the year ended December 31, 2014 . The lower weighted average oil price was partially mitigated by the 35% increase in our oil production to 4.5 million Bbl of oil for the year ended December 31, 2015 , or about 12,306 Bbl of oil per day, as compared to just over 3.3 million Bbl of oil, or about 9,095 Bbl of oil per day, for the year ended December 31, 2014 . This increase d oil production was primarily a result of newly drilled and completed wells in the Delaware Basin, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our natural gas revenues decrease d $2.7 million , or a decrease of 3% , to $75.0 million for the year ended December 31, 2015 , as compared to $77.7 million for the year ended December 31, 2014 . The decrease in natural gas revenues resulted from a lower weighted average natural gas price realized for the year ended December 31, 2015 of $2.71 per Mcf, as compared to $5.08 per Mcf realized for the year ended December 31, 2014 . The lower weighted average natural gas price was partially mitigated by the 81% increase in our natural gas production to 27.7 Bcf for the year ended December 31, 2015 , as compared to 15.3 Bcf for the year ended December 31, 2014 . The increased natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, but also included increased natural gas production associated with our operations in the Delaware Basin and the Eagle Ford shale. +Realized gain (loss) on derivatives . Our realized net gain on derivatives was $77.1 million for the year ended December 31, 2015 , as compared to a realized net gain of $5.0 million for the year ended December 31, 2014 . We realized gain s of $62.3 million , $12.7 million and $2.2 million from our oil, natural gas and natural gas liquids (“NGL”) derivative contracts, respectively, for the year ended December 31, 2015 due to oil and natural gas prices being below the floor prices of most of our costless collar contracts and NGL prices being below the fixed prices of all of our swap contracts. Our realized net gain on derivatives was $5.0 million for the year ended December 31, 2014 . We realized a gain from our oil derivative contracts of +58 +Table of Contents +approximately $5.2 million and a gain of $0.5 million from our NGL derivative contracts for the year ended December 31, 2014 due to oil prices being below the floor prices of some of our costless collar contracts and NGL prices being below the fixed prices of some of our swap contracts, respectively, especially during the latter part of 2014. These gains were partially offset by a loss of $0.7 million on our natural gas derivative contracts, due to natural gas prices being in excess of the ceiling prices of our natural gas costless collar contracts, especially in the early months of 2014. We realized an average gain of approximately $22.89 per Bbl hedged on all of our open oil costless collar contracts during the year ended December 31, 2015 , as compared to an average gain of $2.00 per Bbl hedged for the year ended December 31, 2014 . Our oil volumes hedged for the year ended December 31, 2015 were also 5% higher as compared to the year ended December 31, 2014 . We realized an average gain of approximately $0.73 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2015 , as compared to an average loss of approximately $0.06 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2014 . Our total natural gas volumes hedged for the year ended December 31, 2015 were also 38% higher than the total natural gas volumes hedged for the year ended December 31, 2014 . +Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $39.3 million for the year ended December 31, 2015 , as compared to an unrealized gain of approximately $58.3 million for the year ended December 31, 2014 . During the year ended December 31, 2015 , the net fair value of our open oil, natural gas and NGL derivatives contracts decrease d to approximately $16.3 million from $55.5 million for the year ended December 31, 2014 , resulting in an unrealized loss on derivatives of approximately $39.3 million for the year ended December 31, 2015 . During the year ended December 31, 2015 , the net fair value of our open oil, natural gas and NGL derivative contracts decrease d by $31.9 million , $5.4 million and $1.9 million , respectively, due primarily to the realized gains from oil, natural gas and NGL derivative contracts settled during the year ended December 31, 2015 . +Year Ended December 31, 2014 as Compared to Year Ended December 31, 2013 +Oil and natural gas revenues . Our oil and natural gas revenues increase d $98.7 million to $367.7 million , or an increase of about 37% for the year ended December 31, 2014 , as compared to $269.0 million for the year ended December 31, 2013 . This increase in oil and natural gas revenues corresponds with an increase of 37% in our oil and natural gas production to 5.9 million BOE for the year ended December 31, 2014 from 4.3 million BOE for the year ended December 31, 2013 . Our oil revenues increase d $77.2 million , an increase of 36% , to $290.0 million for the year ended December 31, 2014 , as compared to $212.8 million for the year ended December 31, 2013 . Our oil production increase d 56% to over 3.3 million Bbl of oil, or about 9,095 Bbl of oil per day, as compared to approximately 2.1 million Bbl of oil, or about 5,843 Bbl of oil per day, for the year ended December 31, 2013 due to our ongoing development operations in the Eagle Ford shale and from the better-than-expected performance of a number of our initial wells in the Delaware Basin. Had the weighted average oil price we realized in 2014 remained consistent with the oil price we realized in 2013, the increase in oil production would have resulted in an increase in oil revenue of $118.5 million for the year ended December 31, 2014. This potential increase of $41.2 million in oil revenues was not fully realized in 2014, however, as a result of a lower oil price of $87.37 per Bbl realized for the year ended December 31, 2014, as compared to $99.79 per Bbl realized for the year ended December 31, 2013. Our natural gas revenues increased $21.5 million, an increase of 38%, to $77.7 million for the year ended December 31, 2014, as compared to $56.2 million for the year ended December 31, 2013. Our natural gas production increased 18% to approximately 15.3 Bcf for the year ended December 31, 2014 , as compared to approximately 12.9 Bcf for the year ended December 31, 2013 due to our ongoing development activities in the Eagle Ford shale and the Delaware Basin and to the natural gas production resulting from new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014. This increase in natural gas production in 2014 resulted in increased natural gas revenues of $10.4 million, and the remaining increase in natural gas revenues of $11.1 million was due to a higher natural gas price of $5.08 per Mcf realized for the year ended December 31, 2014 , as compared to $4.35 per Mcf realized for the year ended December 31, 2013. +Realized gain (loss) on derivatives . Our realized net gain on derivatives was approximately $5.0 million for the year ended December 31, 2014, as compared to a realized net loss of approximately $0.9 million for the year ended December 31, 2013. We realized a gain from our oil contracts of $5.2 million and a gain of $0.5 million from our NGL contracts for the year ended December 31, 2014 due to oil prices being below the floor prices of some of our costless collar contracts and NGL prices being below the fixed prices of some of our swap contracts, respectively, especially during the latter part of 2014. These gains were partially offset by a loss of approximately $0.7 million on our natural gas contracts due to natural gas prices being in excess of the ceiling prices of our natural gas costless collar contracts, especially in the early months of 2014. Our realized net loss on derivatives was $0.9 million for the year ended December 31, 2013. We realized a loss from our oil contracts of approximately $2.4 million for the year ended December 31, 2013 due to oil prices being in excess of the ceiling prices of some of our costless collar contracts and the fixed prices of our swap contracts. This loss was partially offset by gains of approximately $0.8 million and $0.7 million on our natural gas and NGL derivative contracts, respectively, due to the respective commodity prices being below the floor prices of our natural gas costless collar contracts and the fixed prices of our NGL swap contracts. We realized an average gain of approximately $2.00 per Bbl hedged on all of our oil costless collar +59 +Table of Contents +contracts during the year ended December 31, 2014, as compared to an average loss of $1.42 per Bbl hedged for the year ended December 31, 2013. Our oil volumes hedged for the year ended December 31, 2014 were also 53% higher as compared to the year ended December 31, 2013. We realized an average loss of approximately $0.06 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2014, as compared to an average gain of approximately $0.10 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2013. Our total natural gas volumes hedged for the year ended December 31, 2014 were also 46% higher than the total natural gas volumes hedged for the year ended December 31, 2013. +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $58.3 million for the year ended December 31, 2014, as compared to an unrealized loss of approximately $7.2 million for the year ended December 31, 2013. During the year ended December 31, 2014, the net fair value of our open oil, natural gas and natural gas liquids derivatives contracts increased to approximately $55.5 million, from $(2.8) million for the year ended December 31, 2013, resulting in an unrealized gain on derivatives of approximately $58.3 million for the year ended December 31, 2014. During the year ended December 31, 2014, the net fair value of our open oil, natural gas and NGL derivative contracts increased by $47.2 million, $9.1 million and $2.0 million, respectively, due primarily to the decrease in the underlying commodities’ futures prices as compared to the year ended December 31, 2013. +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2015 +2014 +2013 +(In thousands, except expenses per BOE) +Expenses: +Production taxes and marketing +$ +35,535 +$ +33,172 +$ +20,973 +Lease operating +58,193 +51,353 +38,720 +Depletion, depreciation and amortization +178,847 +134,737 +98,395 +Accretion of asset retirement obligations +734 +504 +348 +Full-cost ceiling impairment +801,166 +— +21,229 +General and administrative +50,105 +32,152 +20,779 +Total expenses +1,124,580 +251,918 +200,444 +Operating (loss) income +(808,411 +) +179,118 +60,445 +Other income (expense): +Net gain (loss) on asset sales and inventory impairment +908 +— +(192 +) +Interest expense +(21,754 +) +(5,334 +) +(5,687 +) +Interest and other income +2,365 +1,345 +225 +Total other expense +(18,481 +) +(3,989 +) +(5,654 +) +(Loss) income before income taxes +(826,892 +) +175,129 +54,791 +Total income tax (benefit) provision +(147,368 +) +64,375 +9,697 +Net (income) loss attributable to non-controlling interest in subsidiaries +(261 +) +17 +— +Net (loss) income attributable to Matador Resources Company shareholders +$ +(679,785 +) +$ +110,771 +$ +45,094 +Expenses per BOE: +Production taxes and marketing +$ +3.90 +$ +5.65 +$ +4.89 +Lease operating +$ +6.39 +$ +8.75 +$ +9.04 +Depletion, depreciation and amortization +$ +19.63 +$ +22.95 +$ +22.96 +General and administrative +$ +5.50 +$ +5.48 +$ +4.85 +Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014 +Production taxes and marketing. Our production taxes and marketing expenses increase d by $2.4 million to $35.5 million , an increase of 7% , for the year ended December 31, 2015 , as compared to $33.2 million for the year ended December 31, 2014 . On a unit-of-production basis, however, our production taxes and marketing expenses decrease d by 31% to $3.90 per BOE for the year ended December 31, 2015 , as compared to $5.65 per BOE for the year ended December 31, 2014 . The increase in production taxes and marketing expenses on an absolute basis was primarily attributable to higher natural gas marketing expenses of $22.4 million for the year ended December 31, 2015 , as compared to natural gas marketing expenses of $15.2 million for the year ended December 31, 2014 , an increase of $7.2 million , due to the 81% increase in our natural gas production to 27.7 Bcf for the year ended December 31, 2015 , as compared to 15.3 Bcf of natural gas production for the year ended December 31, 2014 . This increase was partially offset by a decrease in our production taxes of $4.8 million to $13.2 million for the year ended December 31, 2015 , as compared to $18.0 million for the year ended December 31, 2014 , primarily +60 +Table of Contents +due to the 30% decrease in oil revenues for the year ended December 31, 2015 , as compared to the year ended December 31, 2014 . +Lease operating expenses. Our lease operating expenses increase d by $6.8 million to $58.2 million , an increase of 13% , for the year ended December 31, 2015 , as compared to $51.4 million for the year ended December 31, 2014 . Our lease operating expenses per unit of production decrease d 27% to $6.39 per BOE for the year ended December 31, 2015 , as compared to $8.75 per BOE for the year ended December 31, 2014 . Our total oil and natural gas production increase d 55% to approximately 9.1 million BOE for the year ended December 31, 2015 from approximately 5.9 million BOE for the year ended December 31, 2014 , including an increase of 35% in oil production to approximately 4.5 million Bbl for the year ended December 31, 2015 , as compared to just over 3.3 million Bbl for the year ended December 31, 2014 , which would typically result in higher lease operating expenses. Oil production was 49% of total production by volume for the year ended December 31, 2015 , as compared to 57% of total production by volume for the year ended December 31, 2014 . The decrease achieved in lease operating expenses on a unit-of-production basis was attributable to several key factors, including (i) no clean-out operations on offsetting producing wells as a result of fracturing operations on newly drilled Eagle Ford wells as compared to the same period in 2014, (ii) a decrease in salt water disposal costs on a per barrel basis, particularly in the Delaware Basin, (iii) reduced service costs impacting lease operating expenses and (iv) a higher percentage of natural gas production, including a significant increase in Haynesville natural gas production, which typically has lower operating costs due to its lack of associated oil and water production. A joint venture controlled by us drilled, completed and began injecting salt water into a new disposal well in the Wolf prospect area in Loving County, Texas in January 2015, which has reduced salt water disposal costs in this area. A second salt water disposal well has been drilled and tested in the Wolf prospect area and began disposing of salt water in the fourth quarter of 2015. At December 31, 2015, this well was operating with temporary facilities, but it is expected to be fully operational with permanent facilities in the latter part of the first quarter of 2016. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d by $44.1 million to $178.8 million , an increase of 33% , for the year ended December 31, 2015 , as compared to $134.7 million for the year ended December 31, 2014 . On a unit-of-production basis, however, our depletion, depreciation and amortization expenses decrease d 15% to $19.63 per BOE for the year ended December 31, 2015 , as compared to $22.95 per BOE for the year ended December 31, 2014 . The absolute increase in our depletion, depreciation and amortization expenses reflects an increase of approximately 55% in our total oil and natural gas production to 9.1 million BOE for the year ended December 31, 2015 from 5.9 million BOE for the year ended December 31, 2014 . The 15% decrease in the per-unit-of-production depletion, depreciation and amortization expenses resulted from the 24% increase in total proved oil and natural gas reserves from 68.7 million BOE at December 31, 2014 to 85.1 million BOE at December 31, 2015, which reserves were added at a lower cost per BOE, as well as from the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2015. +Full-cost ceiling impairment. Due primarily to the sharp decline in oil and natural gas prices during 2015, at December 31, 2015 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling. As a result, we recorded an impairment charge of $801.2 million , exclusive of tax effect, to our net capitalized costs. This charge is reflected in our statement of operations for the year ended December 31, 2015, with the related deferred income tax credit recorded net of a valuation allowance. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the year ended December 31, 2014 . +In determining the full-cost ceiling impairment at December 31, 2015 , we estimated the PV-10 of our total proved oil and natural gas reserves using the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended December 31, 2015 as required under the guidelines established by the SEC, which were $46.79 per Bbl and $2.59 per MMBtu, respectively. If the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended December 31, 2015 had been $42.19 per Bbl and $2.41 per MMBtu, respectively, while all other factors remained constant, our full-cost ceiling would have been reduced by an additional $128.9 million on a pro forma basis. The aforementioned pro forma prices, as estimated for the 12-month period April 2015 through March 2016, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the 11 months ended February 2016, with the price for February 2016 being held constant for March 2016. This pro forma increase in the excess of our net capitalized costs above the full-cost ceiling is attributable to a pro forma reduction of $128.9 million in the PV-10 of our total proved oil and natural gas reserves, including a pro forma decrease in our estimated total proved reserves to 81.2 million BOE, or a reduction of approximately 5% , from our reported estimated proved reserves of 85.1 million BOE at December 31, 2015 , primarily attributable to certain proved undeveloped locations that would no longer be classified as proved undeveloped reserves using the pro forma prices. This calculation of the impact of lower commodity prices on our estimated total proved oil and natural gas reserves and our full-cost ceiling was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our full-cost ceiling and proved reserves. The impact of prices is only one of several variables in the estimation of +61 +Table of Contents +our proved reserves and full-cost ceiling and other factors could have a significant impact on our future proved reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, acquisitions of proved reserves, changes in drilling and completion and operating costs, drilling results, revisions due to well performance and other factors, changes in development plans and production, among others. There are numerous uncertainties inherent in the estimation of proved oil and natural gas reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results. +General and administrative. Our general and administrative expenses increase d by $18.0 million to $50.1 million , an increase of 56% , for the year ended December 31, 2015 , as compared to $32.2 million for the year ended December 31, 2014 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses associated with additional personnel joining the Company during the year ended December 31, 2015 to support our increased land, geoscience, drilling, completion, production, accounting and administration functions, including the addition of 29 new employees in Roswell, New Mexico as a result of the HEYCO Merger in late February 2015. The remaining increase is largely due to a $4.0 million increase in non-cash stock-based compensation expenses to $9.5 million for the year ended December 31, 2015 , as compared to $5.5 million for the year ended December 31, 2014 . The increase in our non-cash stock-based compensation expense was attributable to the increase d expense related to the continued vesting of awards granted from 2012 through 2015 of $9.5 million for the year ended December 31, 2015 , as compared to $5.3 million for the year ended December 31, 2014 . This increase was partially offset by the decrease d expense related to our liability-based stock options of $0.1 million for the year ended December 31, 2015 , as compared to $0.2 million for the year ended December 31, 2014 . This decrease d expense related to our liability-based stock options was attributable to the slight decrease in our stock price from $20.23 per share at December 31, 2014 to $19.77 per share at December 31, 2015 . Our general and administrative expenses increase d by less than 1% on a unit-of-production basis to $5.50 per BOE for the year ended December 31, 2015 , as compared to $5.48 per BOE for the year ended December 31, 2014 . +Interest expense. For the year ended December 31, 2015 , we incurred total interest expense of approximately $25.7 million . We capitalized approximately $3.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2015 and expensed the remaining $21.8 million to operations. For the year ended December 31, 2014 , we incurred total interest expense of approximately $8.2 million . We capitalized approximately $2.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2014 and expensed the remaining $5.3 million to operations. The increase in total interest expense of $17.5 million for the year ended December 31, 2015 , as compared to the year ended December 31, 2014 , was attributable to an increase in both the average debt outstanding and the interest rate of 6.875% under the senior notes in 2015, as compared to the effective interest rate of approximately 3.3% under our Credit Agreement in 2014. In late April 2015, we used a portion of the net proceeds from the April 2015 senior notes and equity offerings to repay a total of $465.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2015 , we had no outstanding borrowings under our Credit Agreement, $0.6 million in outstanding letters of credit and $400.0 million in outstanding senior notes. Due to the higher interest rate on the senior notes as compared to the interest rates under the Credit Agreement, we expect to incur increased interest expense in future periods. +Total income tax (benefit) provision . At December 31, 2015 , our deferred tax assets exceeded our deferred tax liabilities and, as a result, we recorded a valuation allowance of $154.3 million against the deferred tax assets. The total income tax expense for the year ended December 31, 2015 differed from amounts computed by applying the U.S. federal statutory tax rates to the pre-tax loss due primarily to the recording of a valuation allowance against the net deferred tax asset position as a result of the full-cost ceiling impairment recorded for the year ended December 31, 2015 . We recorded a total income tax benefit of $147.4 million for the year ended December 31, 2015 . The total income tax benefit of $147.4 million for the year ended December 31, 2015 is comprised of a current tax expense of $3.0 million , which represents our estimated alternative minimum tax liability (“AMT”), and a deferred tax benefit of $150.3 million . For the year ended December 31, 2014 , we incurred an estimated AMT liability of $0.1 million , which represents the current portion of the income tax provision. The remaining income tax provision of $64.2 million represents deferred taxes for the year ended December 31, 2014 . Our effective tax rate for the year ended December 31, 2014 was 36.8% . Total income tax expense for the year ended December 31, 2014 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily due to the impact of permanent differences between book and taxable income. +Year Ended December 31, 2014 as Compared to Year Ended December 31, 2013 +Production taxes and marketing. Our production taxes and marketing expenses increased by $12.2 million to $33.2 million, an increase of 58%, for the year ended December 31, 2014, as compared to $21.0 million for the year ended December 31, 2013. On a unit-of-production basis, however, our production taxes and marketing expenses increased by only 16% to $5.65 per BOE for the year ended December 31, 2014, as compared to $4.89 per BOE for the year ended December 31, 2013. Much of this increase was attributable to increased production taxes associated with the large increase in our oil production during +62 +Table of Contents +2014 resulting from our drilling operations in the Eagle Ford shale, as well as initial production from our newly drilled wells in the Delaware Basin. Our total production was comprised of approximately 57% oil and 43% natural gas during the year ended December 31, 2014, as compared to approximately 50% oil and 50% natural gas during the year ended December 31, 2013. The increase in production taxes and marketing expenses during the year ended December 31, 2014 also reflected the increase in natural gas production from the Eagle Ford shale where natural gas production taxes are higher than production taxes associated with Haynesville shale natural gas in Louisiana, as well as increased marketing expenses on certain of our non-operated Eagle Ford and Haynesville properties in 2014. +Lease operating expenses. Our lease operating expenses increased by $12.6 million to $51.4 million, an increase of 33%, for the year ended December 31, 2014, as compared to $38.7 million for the year ended December 31, 2013. Our lease operating expenses per unit of production decreased 3% to $8.75 per BOE for the year ended December 31, 2014, as compared to $9.04 per BOE for the year ended December 31, 2013. Our total oil and natural gas production increased 37% to approximately 5.9 million BOE for the year ended December 31, 2014 from approximately 4.3 million BOE for the year ended December 31, 2013, including an increase of 56% in oil production to over 3.3 million Bbl for the year ended December 31, 2014, as compared to 2.1 million Bbl for the year ended December 31, 2013, which would typically result in higher lease operating expenses. Oil production was 57% of total production by volume for the year ended December 31, 2014, as compared to only 50% of total production by volume for the year ended December 31, 2013. The decrease achieved in lease operating expenses on a unit-of-production basis was primarily attributable to the progress we have made in reducing our lease operating expenses in the Eagle Ford shale during the last twelve months, which was primarily attributable to (i) the installation of permanent production facilities on almost all of our Eagle Ford properties, alleviating the need for the extended use of flowback equipment to produce newly completed Eagle Ford wells, (ii) the early use of gas lift on most of our newly completed Eagle Ford wells, (iii) a decrease in salt water disposal costs on a per barrel basis and (iv) continued improvement in overall operational processes in our South Texas operations. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $36.3 million to $134.7 million, an increase of 37%, for the year ended December 31, 2014, as compared to $98.4 million for the year ended December 31, 2013. On a unit-of-production basis, however, our depletion, depreciation and amortization expenses remained essentially flat at $22.95 per BOE for the year ended December 31, 2014, as compared to $22.96 per BOE for the year ended December 31, 2013. The absolute increase in our depletion, depreciation and amortization expenses reflects an increase of approximately 37% in our total oil and natural gas production to 5.9 million BOE for the year ended December 31, 2014 from 4.3 million BOE for the year ended December 31, 2013. This increase on an absolute basis was offset on a unit-of-production basis by the increase in our proved oil and natural gas reserves of 33% to 68.7 million BOE at December 31, 2014 from 51.7 million BOE at December 31, 2013. This increase in total proved oil and natural gas reserves was primarily attributable to the continued development of our acreage in the Eagle Ford shale and the initial delineation and development of our acreage in the Delaware Basin. As a result of this increase in proved oil and natural gas reserves, depletion, depreciation and amortization expenses on a unit-of production basis remained essentially flat year-over-year. +Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the year ended December 31, 2014. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the quarters ended December 31, 2013, September 30, 2013 or June 30, 2013. During the quarter ended March 31, 2013, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an impairment charge of $21.2 million, exclusive of tax effect, to the net capitalized costs of our oil and natural gas properties. This full-cost ceiling impairment of $21.2 million is reflected in our operating expenses for the year ended December 31, 2013, and resulted primarily from the continued low weighted average index price for natural gas used to estimate proved natural gas reserves at March 31, 2013, which was $2.95 per MMBtu for the period of time from April 2012 through March 2013. +General and administrative. Our general and administrative expenses increased by $11.4 million to $32.2 million, an increase of 55%, for the year ended December 31, 2014, as compared to $20.8 million for the year ended December 31, 2013. The increase in our general and administrative expenses was primarily attributable to increased payroll expenses associated with additional personnel joining the Company during the year ended December 31, 2014 to support our increased land, geoscience, drilling, completion and production operations. The remaining increase is largely due to a $1.6 million increase in non-cash stock-based compensation expenses to $5.5 million for the year ended December 31, 2014, as compared to $3.9 million for the year ended December 31, 2013. The increase in our non-cash stock-based compensation expense was attributable to the increased expense related to the continued vesting of awards granted in 2012, 2013 and 2014 of $5.3 million for the year ended December 31, 2014, as compared to $2.9 million for the year ended December 31, 2013. This increase was partially offset by the decreased expense related to our liability-based stock options of $0.2 million for the year ended December 31, 2014, as compared to $1.0 million for the year ended December 31, 2013. This decreased expense related to our liability-based stock options was attributable to the smaller increase in our stock price from $18.64 per share at December 31, +63 +Table of Contents +2013 to $20.23 per share at December 31, 2014, as compared to the larger increase from $8.20 per share at December 31, 2012 to $18.64 per share at December 31, 2013. Our general and administrative expenses increased by only 13% on a unit-of-production basis to $5.48 per BOE for the year ended December 31, 2014, as compared to $4.85 for the year ended December 31, 2013. +Interest expense. For the year ended December 31, 2014, we incurred total interest expense of approximately $8.2 million. We capitalized approximately $2.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2014 and expensed the remaining $5.3 million to operations. For the year ended December 31, 2013, we incurred total interest expense of approximately $7.6 million. We capitalized approximately $1.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2013 and expensed the remaining $5.7 million to operations. The increase in total interest expense for the year ended December 31, 2014 of $0.6 million, as compared to the year ended December 31, 2013, was primarily attributable to higher average outstanding borrowings under our Credit Agreement during 2014, as compared to average outstanding borrowings under our Credit Agreement during 2013. In May 2014, we used a portion of the net proceeds of our public equity offering to repay $180.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2014, we had $340.0 million in borrowings and $0.6 million in letters of credit outstanding under our Credit Agreement, and the effective interest rate on our borrowings was approximately 3.3% per annum. In September 2013, we used a portion of the net proceeds of our September 2013 public equity offering to repay $130.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2013, we had $200.0 million in borrowings and $0.3 million in letters of credit outstanding under our Credit Agreement. +Total income tax provision . We recorded a total income tax provision of approximately $64.4 million for the year ended December 31, 2014, as compared to a total income tax provision of approximately $9.7 million for the year ended December 31, 2013. For the year ended December 31, 2014, we incurred an estimated AMT liability of $0.1 million, which represents the current portion of the income tax provision. The remaining income tax provision of $64.2 million represents deferred taxes for the year ended December 31, 2014. Our effective tax rate for the year ended December 31, 2014 was 36.8%. Total income tax expense for the year ended December 31, 2014 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due to the impact of permanent differences between book and taxable income. For the year ended December 31, 2013, we incurred an estimated AMT liability of $0.4 million, which represents the current portion of the income tax provision. The remaining $9.3 million represents deferred taxes for the year ended December 31, 2013. Our effective tax rate for the year ended December 31, 2013 was 17.7%. Total income tax expense for the year ended December 31, 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to (i) the reversal of the valuation allowance of approximately $8.9 million on our federal deferred tax assets at December 31, 2012, as our federal deferred tax liability exceeded our federal deferred tax assets for the year ended December 31, 2013, (ii) the reversal of a state valuation allowance of approximately $1.3 million, as we believe we will be able to utilize the state net operating losses prior to their expiration and (iii) the impact of permanent differences between book and taxable income. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2016 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for related midstream investments. We continually evaluate potential capital sources, including additional borrowings, equity and debt financings, the sale of midstream or other assets and joint ventures, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows. +At December 31, 2015 , we had cash totaling approximately $16.7 million and restricted cash totaling approximately $44.4 million. Restricted cash represents a portion of the cash paid for the Loving County System by EnLink (as described in Note 5 to the consolidated financial statements in this Annual Report on Form 10-K) directly to a qualified intermediary to facilitate like-kind-exchange transactions for federal income tax purposes, as well as cash held by our less-than-wholly-owned subsidiaries. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions and, in January 2016, the remaining balance of $42.1 million was returned to us by the qualified intermediary to be used for general corporate purposes. By contractual agreement, the cash in the account held by our less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +At December 31, 2015 and February 25, 2016, the borrowing base under our Credit Agreement was $375.0 million . At both dates, we had no outstanding borrowings and approximately $0.6 million in outstanding letters of credit under the Credit Agreement, and we had $400.0 million of outstanding senior notes. +64 +Table of Contents +On April 14, 2015, we issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes are our senior unsecured obligations, are redeemable as described below and were issued at par value. The net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Original Notes mature on April 15, 2023 , and interest is payable semi-annually in arrears on April 15 and October 15 of each year. On October 21, 2015, pursuant to a registered exchange offer, we exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Notes”). The terms of such Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Notes. +On April 21, 2015, we completed a public offering of 7,000,000 shares of our common stock. After deducting offering costs totaling approximately $1.2 million , we received net proceeds of approximately $187.6 million . We used a portion of the net proceeds to repay $85.0 million in outstanding borrowings under our Credit Agreement, which amounts may be reborrowed in accordance with the terms of that facility. The remaining $102.6 million of net proceeds was used to fund a portion of our working capital expenditures, including the addition of a third drilling rig in the Delaware Basin in late July 2015 and targeted acquisitions of additional acreage in the Delaware Basin, as well as in the Eagle Ford shale, and for other general working capital needs. +On October 1, 2015, we completed the sale of our wholly-owned subsidiary that owned the Loving County System to EnLink. The Loving County System includes the Processing Plant and approximately six miles of high-pressure gathering pipeline which connects our gathering system to the Processing Plant. Pursuant to the terms of the transaction, EnLink paid cash consideration of approximately $143.4 million, excluding customary purchase price adjustments. In conjunction with the sale of the Loving County System, we dedicated our leasehold interests in Loving County as of the closing date pursuant to a 15-year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. In addition, we retained our natural gas gathering system up to a central delivery point and our other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. +In response to the sharp decrease in oil and natural gas prices experienced throughout 2015 and early 2016 , we have reduced our 2016 estimated capital expenditure budget to $325.0 million as compared to actual capital expenditures of $482.1 million (excluding capital expenditures associated with the HEYCO Merger) for the year ended December 31, 2015 . Our estimated capital expenditure budget for 2016 of $325.0 million consists of approximately $260.0 million for drilling, completions, facilities and infrastructure, $40.0 million principally for the completion of new midstream facilities in the Delaware Basin to support our operations there and $25.0 million for land acquisitions and seismic data, primarily in the Delaware Basin. Development of our Delaware Basin assets will be the primary driver of our growth in 2016 . Approximately $315.0 million , or 97% , of our 2016 estimated capital expenditures will be allocated to further delineation and development of our growing leasehold position in the Delaware Basin. Our 2016 Delaware Basin drilling program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of the Ranger and Arrowhead prospect areas. The $40.0 million in midstream capital expenditures is expected to primarily fund the construction and installation of a cryogenic natural gas processing plant with approximately 60 MMcf per day of inlet capacity and a natural gas gathering system in the Rustler Breaks prospect area in Eddy County, New Mexico. This plant is expected to be operational by the third quarter of 2016. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations in 2016 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2016 and the hedges we currently have in place. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil and natural gas prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. As of February 25, 2016 , we had 44% and 44% of our estimated remaining 2016 oil and natural gas production, respectively, hedged. We currently have no hedges in place for oil or natural gas liquids beyond 2016; however, we have a portion of our anticipated natural gas volumes hedged in 2017. +Due to the sharp decline in commodity prices since mid- 2014 , we anticipate that our operating cash flows in 2016 will be less than in 2015 . Further, if our exploration, development and production activities result in less cash flows than anticipated, we may seek additional sources of capital, including through additional borrowings under our Credit Agreement, additional credit arrangements, the sale of midstream or other assets or acreage or entering into one or more joint ventures, none of which may be available. In addition to future borrowings under our Credit Agreement, we may also seek to raise additional funds by issuing debt securities or selling shares of our common stock or securities convertible or exercisable into our common stock +65 +Table of Contents +(including debt securities or other preferential securities) in the public markets or otherwise. Any such sales of equity or convertible securities would dilute the ownership interest of our existing shareholders. There is no guarantee that we would be able to sell such debt or equity securities on terms acceptable to us. It is also possible that, to the extent we are not able to obtain additional sources of capital, we may modify our planned capital expenditure budget for 2016 accordingly to further reduce our capital spending and rate of growth or enter into one or more joint ventures or other alternative financings. Exploration and development activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and the borrowing base under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” +Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing approximately $325.0 million in capital for acquisition, exploration and development and midstream activities in 2016 as follows. +Amount +(in millions) +Exploration and development drilling and completion costs, including production facilities and infrastructure +$ +260.0 +Midstream activities +40.0 +Leasehold acquisition and 2-D and 3-D seismic data +25.0 +Total +$ +325.0 +Our 2016 capital expenditures may be adjusted as business conditions warrant, as evidenced by the substantial reduction in our 2016 capital expenditure budget, as compared to our 2015 capital spending, in response to the sharp decline in oil and natural gas prices since mid- 2014 . The amount, timing and allocation of our capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline further or costs increase significantly, we could defer a portion of our anticipated capital expenditures until later periods to conserve cash or to focus on those projects that we believe have the highest expected returns and potential to generate near-term cash flows. For example, if oil prices drop and remain below $30.00 per Bbl, we have the flexibility to reduce the number of rigs we are operating from three rigs to two rigs either for a short time or for the remainder of 2016, beginning as early as the second quarter of 2016. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Our cash flows for the years ended December 31, 2015, 2014 and 2013 are presented below. +Year Ended December 31, +2015 +2014 +2013 +(In thousands) +Net cash provided by operating activities +$ +208,535 +$ +251,481 +$ +179,470 +Net cash used in investing activities +(425,154 +) +(570,531 +) +(366,939 +) +Net cash provided by financing activities +224,944 +321,170 +191,661 +Net change in cash +$ +8,325 +$ +2,120 +$ +4,192 +Cash Flows Provided by Operating Activities +Net cash provided by operating activities decreased by $42.9 million to $208.5 million for the year ended December 31, 2015 , as compared to net cash provided by operating activities of $251.5 million for the year ended December 31, 2014 . Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $199.6 million for the year ended December 31, 2015 from $257.5 million for the year ended December 31, 2014 . This decrease is primarily attributable to the decrease in oil revenues from 2014 to 2015, resulting from a significantly lower weighted average oil price realized for the year ended December 31, 2015 of $45.27 per Bbl, as compared to $87.37 per Bbl realized for the year ended December 31, 2014 . This decrease was partially offset by the increase of approximately 35% in our oil production to approximately 4.5 million Bbl from just over 3.3 million Bbl during the respective periods. Changes in our operating assets and +66 +Table of Contents +liabilities between December 31, 2014 and December 31, 2015 also resulted in a net increase of approximately $15.0 million in net cash provided by operating activities for the year ended December 31, 2015 , as compared to the year ended December 31, 2014 . +Net cash provided by operating activities increased by $72.0 million to $251.5 million for the year ended December 31, 2014 , as compared to net cash provided by operating activities of $179.5 million for the year ended December 31, 2013 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $257.5 million for the year ended December 31, 2014 from $185.7 million for the year ended December 31, 2013 . This increase is primarily attributable to the increase of approximately 56% in our oil production to just over 3.3 million Bbl from approximately 2.1 million Bbl during the respective periods. Changes in our operating assets and liabilities between December 31, 2014 and December 31, 2013 also resulted in a net increase of approximately $0.2 million in net cash provided by operating activities for the year ended December 31, 2014 , as compared to the year ended December 31, 2013 . +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service agreements in order to minimize ongoing future commitments. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities decreased by $145.4 million to $425.2 million for the year ended December 31, 2015 from $570.5 million for the year ended December 31, 2014 . This decrease in net cash used in investing activities included (i) a decrease of $128.1 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2015 , as compared to the year ended December 31, 2014 , (ii) proceeds from the sale of the Loving County System to EnLink of $139.8 million , (iii) an increase of approximately $55.3 million in expenditures for other property and equipment, which includes the Processing Plant and salt water disposal facilities we constructed in Loving County, Texas as well as initial costs associated with a natural gas processing plant we are constructing in Eddy County, New Mexico, and new pipeline infrastructure, (iv) cash used in the HEYCO Merger of $24.0 million and (v) an increase in our restricted cash of $43.1 million attributable to the escrow account associated with potential like-kind-exchange transactions in connection with the sale of the Loving County System to EnLink. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2015 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as to our operated and non-operated drilling activities in the Eagle Ford shale play and certain non-operated drilling activities in the Haynesville shale. +Net cash used in investing activities increased by $203.6 million to $570.5 million for the year ended December 31, 2014 from $366.9 million for the year ended December 31, 2013 . This increase in net cash used in investing activities reflected an increase of $197.7 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2014 , as compared to the year ended December 31, 2013 , and an increase of approximately $5.2 million in expenditures for other property and equipment, which included new pipeline infrastructure associated with our properties in the Eagle Ford shale, but also reflects initial costs associated with construction of the Processing Plant and a salt water disposal facility in Loving County, Texas. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2014 was primarily attributable to our operated and non-operated drilling and completion activities in the Eagle Ford shale play, as well as to our initial operated drilling activities in the Delaware Basin and certain non-operated drilling activities in Haynesville shale. We also used a portion of this cash to acquire approximately 29,300 gross (21,800 net) additional acres in the Delaware Basin in 2014, along with approximately 3,200 gross (3,000 net) acres in the Eagle Ford shale. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $224.9 million for the year ended December 31, 2015 , as compared to net cash provided by financing activities of $321.2 million for the year ended December 31, 2014 . The net cash provided by financing activities for the year ended December 31, 2015 was primarily attributable to the total proceeds of our public equity offering of $188.7 million , the total proceeds of our Notes issuance of $400.0 million , borrowings under our Credit Agreement of $125.0 million and capital contributed from the non-controlling interest owners in our less-than-wholly-owned subsidiaries of $0.6 million , offset by the costs of the public equity offering of $1.2 million , the costs of the Notes issuance of $9.6 million , the repayment of $477.0 million in borrowings under our Credit Agreement during the period and the payment of $1.6 million in taxes related to net share settlement of stock-based compensation. +67 +Table of Contents +Net cash provided by financing activities was $321.2 million for the year ended December 31, 2014 , as compared to net cash provided by financing activities of $191.7 million for the year ended December 31, 2013 . The net cash provided by financing activities for the year ended December 31, 2014 was primarily attributable to the total proceeds from our May 2014 public equity offering of $181.9 million and borrowings of $320.0 million under our Credit Agreement during the period, offset by the costs of the offering of $0.6 million incurred during the period and by the repayment of $180.0 million in borrowings under our Credit Agreement during the period. +Net cash provided by financing activities was $191.7 million for the year ended December 31, 2013 . The net cash provided by financing activities for the year ended December 31, 2013 was principally due to the total proceeds from our September 2013 public equity offering of $149.1 million and total borrowings of $180.0 million under our Credit Agreement during the period, offset by the costs of the offering of $7.4 million incurred during the period and by the repayment of $130.0 million in borrowings under our Credit Agreement during the period. +See Note 6 to the consolidated financial statements in this Annual Report on Form 10-K for a summary of our debt, including our Credit Agreement and the Notes. +Off-Balance Sheet Arrangements +From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2015 , the material off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements, (ii) non-operated drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) firm transportation and fractionation commitments, (v) agreements to construct facilities and (vi) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more information regarding the Company’s off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2015 . +Payments Due by Period +Total +Less Than 1 Year +1-3 Years +3-5 Years +More Than 5 Years +(In thousands) +Contractual Obligations: +Revolving credit borrowings and term loan, including letters of credit (1) +$ +600 +$ +— +$ +600 +$ +— +$ +— +Senior unsecured notes (2) +400,000 +— +— +— +400,000 +Office leases +27,062 +2,017 +4,920 +5,130 +14,995 +Non-operated drilling commitments (3) +5,652 +5,652 +— +— +— +Drilling rig contracts (4) +43,450 +23,156 +20,294 +— +— +Asset retirement obligations +15,420 +254 +1,136 +2,563 +11,467 +Natural gas processing and transportation agreements (5) +12,618 +11,423 +1,195 +— +— +Gas plant engineering, procurement, construction and installation contract (6) +21,500 +21,500 +— +— +— +Total contractual cash obligations +$ +526,302 +$ +64,002 +$ +28,145 +$ +7,693 +$ +426,462 +__________________ +(1) +At December 31, 2015 , we had no borrowings outstanding under our Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. These borrowings mature in October 2020. +(2) +The amounts included in the table above represent principal maturities only. +(3) +At December 31, 2015 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2015 . If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $5.7 million at December 31, 2015 , which we expect to incur within the next year. +(4) +We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of our commitments for the drilling services to be provided, which have typically been for one year or less, although in 2014, we entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were +68 +Table of Contents +experiencing heavy demand for drilling rigs. Should we elect to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate termination obligations under our drilling rig contracts were approximately $43.5 million at December 31, 2015 . +(5) +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. The undiscounted minimum commitments under this agreement total approximately $3.0 million at December 31, 2015 . Effective October 1, 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. The undiscounted minimum initial commitments under this agreement total approximately $216.1 million at December 31, 2015 ; however, at the end of each year of the agreement, we can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years under the contract. As such, we have the ability to unilaterally reduce the transportation and processing commitment if our production in the Loving County area is less than our currently projected production. In addition, if we elect to reduce the transportation and processing commitment in any year, we have the ability to elect to increase the committed volumes in any future year to the originally agreed transportation and processing commitment. If we do not meet the volume commitment for transportation and processing at the facility in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. If we did not use any of our commitment and elected to reduce our future years’ commitment to zero, the deficiency payment required to be paid in 2016 under the contract would be approximately $9.6 million at December 31, 2015 and no further deficiency payments would be required in future years. +(6) +We entered into an agreement with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in the Rustler Breaks prospect area in Eddy County, New Mexico in 2015. This plant is expected to process a portion of our natural gas produced from certain of our wells in the Delaware Basin, as well as third-party natural gas. The plant is scheduled to be completed and placed in service in the third quarter of 2016. +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Prices for oil, natural gas and natural gas liquids affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Further declines in oil, natural gas or natural gas liquids prices would not only further reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Throughout 2015, oil and natural gas prices continued to decline sharply from their most recent highs in 2014. Oil prices have decreased 68% from $107.26 per Bbl in mid-June to $34.73 per Bbl in late December 2015, and natural gas prices have decreased 71% from $6.15 per MMBtu in mid-February 2014 to $1.76 per MMBtu in mid-December 2015. These sharp declines in oil and natural gas prices impacted our revenues, profitability and cash flows in 2015, as compared to 2014, and further declines in the price of oil and natural gas could have an adverse impact on our borrowing capacity, ability to obtain additional capital, revenues, profitability and cash flows. We are uncertain when, or if, oil and natural gas prices may rise from their current levels, and in fact, oil and natural gas prices may decrease further in future periods. +For the year ended December 31, 2015 , oil prices averaged $48.79 per Bbl, ranging from a high of $61.43 per Bbl in mid-June to a low of $34.73 per Bbl in late December, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $45.27 per Bbl ( $59.13 per Bbl including realized gains from oil derivatives) for our oil production for the year ended December 31, 2015 , as compared to $87.37 per Bbl ( $88.94 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2014 . At February 25, 2016 , the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had declined further, closing at $33.07 per Bbl, as compared to $50.99 per Bbl at February 25, 2015 . +For the year ended December 31, 2015 , natural gas prices averaged $2.63 per MMBtu, ranging from a high of approximately $3.23 per MMBtu in mid-January to a low of approximately $1.76 per MMBtu in mid-December, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $2.71 per Mcf ( $3.24 per Mcf including realized gains from natural gas and NGL derivatives) for our natural gas +69 +Table of Contents +production for the year ended December 31, 2015 , as compared to $5.08 per Mcf ( $5.06 per Mcf including realized losses from natural gas and NGL derivatives) for the year ended December 31, 2014 . At February 25, 2016 , the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had declined further, closing at $1.71 per MMBtu, as compared to $2.89 per MMBtu at February 25, 2015 . +In response to the continued decline in oil and natural gas prices experienced throughout 2015 and into early 2016 , we have reduced our 2016 estimated capital expenditure budget to $325.0 million , as compared to actual capital expenditures of $482.1 million (excluding capital expenditures associated with the HEYCO Merger) for the year ended December 31, 2015 . We plan to operate three contracted drilling rigs in the Delaware Basin throughout 2016 , although should oil prices drop and remain below $30.00 per Bbl, we have the flexibility to reduce the number of rigs we are operating from three rigs to two rigs, either for a short time or for the remainder of 2016 , beginning as early as the second quarter of 2016. This could reduce our estimated 2016 capital expenditures by approximately $50.0 million. Our 2016 estimated capital expenditure budget of $325.0 million (assuming a three-rig program) consists of approximately $260.0 million for drilling, completions, facilities and infrastructure, $40.0 million principally for the completion of new midstream facilities in the Delaware Basin to support our operations there and $25.0 million for land acquisitions and seismic data, primarily in the Delaware Basin. Development of our Delaware Basin assets will be the primary driver of our projected growth in 2016 . Approximately $315.0 million , or 97% , of our 2016 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position in the Delaware Basin. Our 2016 Delaware Basin drilling program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of the Ranger and Arrowhead prospect areas. The $40.0 million in midstream capital expenditures is expected to primarily fund completion of the construction and installation of a cryogenic natural gas processing plant with approximately 60 MMcf per day of inlet capacity and a natural gas gathering system in the Rustler Breaks prospect area in Eddy County, New Mexico. This plant is expected to be operational by the third quarter of 2016. +We do not plan to drill any operated Eagle Ford shale wells in South Texas or Haynesville shale natural gas wells in Northwest Louisiana during 2016 . Approximately $5.6 million , or 2% , of our 2016 estimated capital expenditures will be allocated to the Eagle Ford shale to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, if desired, and approximately $4.4 million , or just over 1% , of our 2016 estimated capital expenditures will be allocated to participation in non-operated Haynesville shale wells. Approximately 92% of our Eagle Ford acreage and essentially all of our Haynesville and Cotton Valley acreage was either held by production at December 31, 2015 or not burdened by lease expirations before 2017 . +Coincident with the recent declines in commodity prices, we have experienced price reductions from our service providers for many of the products and services we use in our drilling, completion and production operations. If oil and natural gas prices remain at their current levels for a longer period of time or should they decline further, we would anticipate receiving additional price reductions for drilling, completion and production products and services, although we can provide no assurances that these price reductions will occur or of their eventual magnitude. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and natural gas liquids price declines, however, drilling additional oil or natural gas wells may not be economical, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our +70 +Table of Contents +estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report on Form 10-K for further details on our accounting policies at December 31, 2015 . Such information is incorporated herein by reference. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related reserves. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments typically consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the +71 +Table of Contents +purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized gain (loss) on derivatives.” Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flow from operations, liquidity or capital resources. The fair value of our derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under Revenues as “Realized gain (loss) on derivatives.” +Revenue Recognition +We follow the sales method of accounting for our oil, natural gas and natural gas liquids revenue, whereby we recognize revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural gas and natural gas liquids are produced and sold, and we accrue for revenue earned but not yet received. +Stock-Based Compensation +We account for stock-based compensation in accordance with ASC 718. During 2015 , 2014 , 2013 and 2012 all stock option awards were granted under our 2012 Long-Term Incentive Plan, or the Amended and Restated 2012 Long-Term Incentive Plan for awards granted after June 10, 2015, and were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these awards have been accounted for as liability instruments. We used the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, we estimated the future volatility of our stock using the historical volatility of the common stock of a group of companies we consider to be a representative peer group. Management believes that these average historical volatility rates are currently the best available indicator of future volatility. +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards are recognized based on the fair value of our stock on the date of the grant. See Note 8 to the consolidated financial statements in this Annual Report on Form 10-K for further details on our stock-based compensation at December 31, 2015. Such information is incorporated herein by reference. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +72 +Table of Contents +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report on Form 10-K. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” +Recent Accounting Pronouncements +Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued Accounting Standards Update, or ASU, 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. We are currently evaluating the new guidance and have not determined the impact this standard may have on our consolidated financial statements. +Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. We are currently evaluating the impact, if any, of the adoption of this ASU on our consolidated financial statements. +Interest - Imputation of Interest. In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 935-30): Simplifying the Presentation of Debt Issuance Costs, which requires companies that have historically presented debt issuance costs as an asset to present those costs as a direct deduction from the carrying amount of the underlying debt liability. The guidance requires retrospective application in financial statements issued for fiscal years and interim periods beginning after December 15, 2015 but early adoption is permitted. We adopted this ASU effective June 30, 2015. See Note 2 to the consolidated financial statements in this Annual Report on Form 10-K for a description of the impact of the adoption of this standard on our consolidated financial statements. +Income Taxes. In November 2015, the FASB issued ASU 2015-17 , Income Taxes (Topic 740), which requires deferred income tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. The standard permitted either prospective or retrospective application. We elected to apply the standard retrospectively. We adopted ASU 2015-17, Income Taxes (Topic 740), effective December 31, 2015. See Note 2 to the consolidated financial statements in this +73 +Table of Contents +Annual Report on Form 10-K for a description of the impact of the adoption of this standard on our consolidated financial statements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and natural gas liquids fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our future anticipated production. +We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2015 , The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2015 , we have entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any oil contract is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. +When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +See Note 11 to the consolidated financial statements in this Annual Report on Form 10-K for a summary of our open derivative financial instruments at December 31, 2015 . Such information is incorporated herein by reference. +Effect of Recent Derivatives Legislation. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain of these regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2015 we had no outstanding borrowings under our Credit Agreement and $400.0 million in Notes outstanding at an interest rate of 6.875% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +74 +Table of Contents +Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our oil, natural gas and natural gas liquids derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 25, 2016 were The Bank of Nova Scotia, SunTrust Bank and BMO Harris Financing (Bank of Montreal) (or affiliates thereof), which are lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with RBC, Comerica Bank, The Bank of Nova Scotia, SunTrust Bank, BMO Harris Financing (Bank of Montreal) or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2015, 2014 and 2013 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report on Form 10-K. See the index to the financial statements in Item 15. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +On April 9, 2014, the Audit Committee of the Board of Directors of the Company approved the appointment of KPMG LLP (“KPMG”) as the Company’s independent registered public accounting firm for the year ending December 31, 2014. This appointment constituted the dismissal of Grant Thornton LLP (“Grant Thornton”) as the Company’s independent registered public accounting firm. Grant Thornton completed its engagement as the Company’s independent registered public accounting firm for the year ended December 31, 2013 upon the filing of the Company’s Annual Report on Form 10-K. The Audit Committee made its decision in connection with its annual review of the Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms. +Grant Thornton’s audit report on the Company’s consolidated financial statements for the year ended December 31, 2013 did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope, or accounting principles. +During the year ended December 31, 2013 and through the current date, there were no (i) disagreements (as defined in Item 304(a)(1)(iv) of Regulation S-K) between the Company and Grant Thornton on any matter of accounting principle or practice, financial statement disclosure or auditing scope or procedure which, if not resolved to Grant Thornton’s satisfaction, would have caused it to make reference to the matter in conjunction with its report on the Company’s consolidated financial statements for the year, or (ii) reportable events (as defined in Item 304(a)(1)(v) of Regulation S-K). +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +75 +Table of Contents +As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2015 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2015 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2015 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +76 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2015 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2015 and 2014 , and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the each of the years in the two-year period ended December 31, 2015 , and our report dated February 29, 2016 expressed an unqualified opinion on those consolidated financial statements. +/s/ KPMG LLP +Dallas, Texas +February 29, 2016 +77 +Table of Contents +Item 9B. Other Information. +Not applicable. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report on Form 10-K and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +78 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report on Form 10-K: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2015 and 2014 , Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 . +2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K. +79 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011). +2.2 +Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 20, 2015).* +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to our Annual Report on Form 10-K for the year ended December 31, 2014). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.4 to our Annual Report on Form 10-K for the year ended December 31, 2014). +2.5 +Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.5 to our Annual Report on Form 10-K for the year ended December 31, 2014).* +2.6 +Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on March 2, 2015).* +2.7 +Amendment No. 5 to Agreement and Plan of Merger, dated as of April 15, 2015, by and among HEYCO Energy Group, Inc., Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on April 15, 2015). +2.8 +Amendment No. 6 to Agreement and Plan of Merger, dated as of July 20, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.9 +Amendment No. 7 to Agreement and Plan of Merger, dated as of August 24, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.10 +Amendment No. 8 to Agreement and Plan of Merger, dated as of September 18, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +3.1 +Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011). +3.2 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13, 2012). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 25, 2016). +3.5 +Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on March 2, 2015). +80 +Table of Contents +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 2, 2015). +4.3 +Voting Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on March 2, 2015). +4.4 +Registration Rights Agreement, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on April 14, 2015). +4.5 +Indenture, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015). +4.6 +First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf Midstream, LLC, the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 5, 2015). +4.7 +Second Supplemental Indenture, dated as of November 4, 2015, by and among Matador Resources Company, MRC Permian LKE Company, LLC, the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.8† +First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.10† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.11† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +81 +Table of Contents +10.12† +Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.13† +Matador Resources Company Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.14† +Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.15† +First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.16† +Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.17† +Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.18† +Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.19† +Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.20† +Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.21† +Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.22† +Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.23† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.24 +Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011 (incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.25 +First Amendment to Purchase Sale and Participation Agreement, dated as of June 12, 2013, by and between MRC Energy Company and Orca/ICI Development (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.26† +Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.27† +Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.28† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.29† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011). +82 +Table of Contents +10.30† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.31† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.32† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.33† +Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.34† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.35† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.36† +Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.37 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.38 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.39 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.40 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.41 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.42 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.43 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.44 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +83 +Table of Contents +10.45 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.46 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.47† +Form of Employment Agreement between Matador Resources Company and each of Craig N. Adams and Ryan C. London (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.48† +Letter Agreement between Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., dated February 26, 2015 (incorporated by reference to Exhibit 10.51 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.49† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.50 +Guaranty, dated February 27, 2015, by Matador Resources Company in favor of PlainsCapital Bank (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 2, 2015). +10.51† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.52† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.55 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.53† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith). +10.54† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (filed herewith). +10.55† +Amended and Restated Independent Contractor Agreement by and among Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., effective as of April 1, 2015 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 11, 2015). +10.56 +Purchase Agreement, dated as of April 9, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 14, 2015). +10.57† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.58 +Separation Agreement and Release, dated as of August 31, 2015, by and between Matador Resources Company and Ryan C. London (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q/A for the quarter ended September 30, 2015). +10.59† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Grant Thornton LLP (filed herewith). +23.3 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +84 +Table of Contents +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +† +Indicates a management contract or compensatory plan or arrangement. +* +Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +85 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +February 29, 2016 +By: +/s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +86 +Table of Contents +Signature +Title +Date +/s/ Joseph Wm. Foran +Chairman and Chief Executive Officer (Principal Executive Officer) +February 29, 2016 +Joseph Wm. Foran +/s/ David E. Lancaster +Executive Vice President and +Chief Financial Officer +(Principal Financial Officer) +February 29, 2016 +David E. Lancaster +/s/ Robert T. Macalik +Vice President and Chief Accounting Officer (Principal Accounting Officer) +February 29, 2016 +Robert T. Macalik +/s/ Reynald A. Baribault +Director +February 29, 2016 +Reynald A. Baribault +/s/ David M. Laney +Director +February 29, 2016 +David M. Laney +/s/ Gregory E. Mitchell +Director +February 29, 2016 +Gregory E. Mitchell +/s/ Steven W. Ohnimus +Director +February 29, 2016 +Steven W. Ohnimus +/s/ Carlos M. Sepulveda, Jr. +Director +February 29, 2016 +Carlos M. Sepulveda, Jr. +/s/ Margaret B. Shannon +Director +February 29, 2016 +Margaret B. Shannon +/s/ Don C. Stephenson +Director +February 29, 2016 +Don C. Stephenson +/s/ George M. Yates +Director +February 29, 2016 +George M. Yates +87 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report on Form 10-K in reference to crude oil or other liquid hydrocarbons. +Bcf . One billion cubic feet. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +FERC . Federal Energy Regulatory Commission. +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may +88 +Table of Contents +also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil or other liquid hydrocarbons. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +89 +Table of Contents +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +90 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2015, 2014 and 2013 +Contents +Reports of Independent Registered Public Accounting Firms +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2015 and 2014 +F-4 +Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013 +F-5 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013 +F-6 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 +F-7 +Notes to Consolidated Financial Statements +F-8 +Unaudited Supplementary Information +F-35 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited the accompanying consolidated balance sheets of Matador Resources Company (a Texas corporation) and subsidiaries (collectively the “Company”) as of December 31, 2015 and 2014 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2015 . These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Matador Resources Company and subsidiaries as of December 31, 2015 and 2014 , and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2015 , in conformity with U.S. generally accepted accounting principles. +As discussed in Note 2 of the financial statements, the Company changed its method of accounting for debt issuance costs effective January 1, 2014. Additionally, as discussed in Note 2 of the financial statements, the Company changed its method of accounting for deferred taxes effective January 1, 2014. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015 , based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 29, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +/s/ KPMG LLP +Dallas, Texas +February 29, 2016 +F-2 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Shareholders +Matador Resources Company +We have audited the accompanying consolidated balance sheet of Matador Resources Company (a Texas corporation) and subsidiaries (collectively the “Company”) as of December 31, 2013 (not presented herein), and the related consolidated statement of operations, changes in shareholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Matador Resources Company and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. +/s/ GRANT THORNTON LLP +Dallas, Texas +March 17, 2014 +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2015 +2014 +ASSETS +Current assets +Cash +$ +16,732 +$ +8,407 +Restricted cash +44,357 +609 +Accounts receivable +Oil and natural gas revenues +16,616 +28,976 +Joint interest billings +16,999 +6,925 +Other +10,794 +9,091 +Derivative instruments +16,284 +55,549 +Lease and well equipment inventory +2,022 +1,212 +Prepaid expenses and other assets +3,203 +1,649 +Total current assets +127,007 +112,418 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +2,122,174 +1,617,913 +Unproved and unevaluated +387,504 +264,419 +Other property and equipment +86,387 +43,472 +Less accumulated depletion, depreciation and amortization +(1,583,659 +) +(603,732 +) +Net property and equipment +1,012,406 +1,322,072 +Other assets +Other assets +1,448 +— +Total other assets +1,448 +— +Total assets +$ +1,140,861 +$ +1,434,490 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +10,966 +$ +17,526 +Accrued liabilities +92,369 +107,356 +Royalties payable +16,493 +14,461 +Amounts due to affiliates +5,670 +2,146 +Advances from joint interest owners +700 +— +Deferred gain on plant sale +4,830 +— +Amounts due to joint ventures +2,793 +— +Income taxes payable +2,848 +444 +Other current liabilities +161 +103 +Total current liabilities +136,830 +142,036 +Long-term liabilities +Borrowings under Credit Agreement +— +338,199 +Senior unsecured notes payable +391,254 +— +Asset retirement obligations +15,166 +11,640 +Amounts due to joint ventures +3,956 +— +Deferred income taxes +— +73,534 +Deferred gain on plant sale +102,506 +— +Other long-term liabilities +2,190 +2,540 +Total long-term liabilities +515,072 +425,913 +Commitments and contingencies (Note 13) +Shareholders’ equity +Common stock — $0.01 par value, 120,000,000 and 80,000,000 shares authorized; 85,567,021 and 73,373,744 shares issued; 85,564,435 and 73,342,777 shares outstanding, respectively +856 +734 +Additional paid-in capital +1,026,077 +724,819 +Retained (deficit) earnings +(538,930 +) +140,855 +Total Matador Resources Company shareholders’ equity +488,003 +866,408 +Non-controlling interest in subsidiaries +956 +133 +Total shareholders’ equity +488,959 +866,541 +Total liabilities and shareholders’ equity +$ +1,140,861 +$ +1,434,490 +The accompanying notes are an integral part of these financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2015 +2014 +2013 +Revenues +Oil and natural gas revenues +$ +278,340 +$ +367,712 +$ +269,030 +Realized gain (loss) on derivatives +77,094 +5,022 +(909 +) +Unrealized (loss) gain on derivatives +(39,265 +) +58,302 +(7,232 +) +Total revenues +316,169 +431,036 +260,889 +Expenses +Production taxes and marketing +35,535 +33,172 +20,973 +Lease operating +58,193 +51,353 +38,720 +Depletion, depreciation and amortization +178,847 +134,737 +98,395 +Accretion of asset retirement obligations +734 +504 +348 +Full-cost ceiling impairment +801,166 +— +21,229 +General and administrative +50,105 +32,152 +20,779 +Total expenses +1,124,580 +251,918 +200,444 +Operating (loss) income +(808,411 +) +179,118 +60,445 +Other income (expense) +Net gain (loss) on asset sales and inventory impairment +908 +— +(192 +) +Interest expense, net of amounts capitalized +(21,754 +) +(5,334 +) +(5,687 +) +Interest and other income +2,365 +1,345 +225 +Total other expense +(18,481 +) +(3,989 +) +(5,654 +) +(Loss) income before income taxes +(826,892 +) +175,129 +54,791 +Income tax provision (benefit) +Current +2,959 +133 +404 +Deferred +(150,327 +) +64,242 +9,293 +Total income tax (benefit) provision +(147,368 +) +64,375 +9,697 +Net (loss) income +(679,524 +) +110,754 +45,094 +Net (income) loss attributable to non-controlling interest in subsidiaries +(261 +) +17 +— +Net (loss) income attributable to +Matador Resources Company shareholders +$ +(679,785 +) +$ +110,771 +$ +45,094 +Earnings (loss) per common share +Basic +$ +(8.34 +) +$ +1.58 +$ +0.77 +Diluted +$ +(8.34 +) +$ +1.56 +$ +0.77 +Weighted average common shares outstanding +Basic +81,537 +70,229 +58,777 +Diluted +81,537 +70,906 +58,929 +The accompanying notes are an integral part of these financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +For the Years Ended December 31, 2015, 2014 and 2013 +(In thousands) +Total shareholders' equity attributable to Matador Resources Company +Additional +paid-in +capital +Retained earnings (deficit ) +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders' equity +Common Stock +Preferred Stock +Shares +Amount +Shares +Amount +Shares +Amount +Balance at January 1, 2013 +56,779 +$ +568 +— +$ +— +$ +404,311 +$ +(15,010 +) +1,201 +$ +(10,765 +) +$ +379,104 +$ +— +$ +379,104 +Issuance of common stock +9,780 +98 +— +— +148,971 +— +— +— +149,069 +— +149,069 +Cost to issue equity +— +— +— +— +(7,390 +) +— +— +— +(7,390 +) +— +(7,390 +) +Issuance of common stock to Board members and advisors +22 +— +— +— +57 +— +— +— +57 +— +57 +Stock options expense related to equity-based awards +— +— +— +— +1,232 +— +— +— +1,232 +— +1,232 +Liability-based stock option awards settled +— +— +— +— +162 +— +— +— +162 +— +162 +Restricted stock issued +378 +4 +— +— +(4 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +(22 +) +— +105 +— +(22 +) +— +(22 +) +Restricted stock and restricted stock units expense +— +— +— +— +1,618 +— +— +— +1,618 +— +1,618 +Current period net income +— +— +— +— +— +45,094 +— +— +45,094 +— +45,094 +Balance at December 31, 2013 +66,959 +670 +— +— +548,935 +30,084 +1,306 +(10,765 +) +568,924 +— +568,924 +Issuance of common stock +7,500 +75 +— +— +181,800 +— +— +— +181,875 +— +181,875 +Cost to issue equity +— +— +— +— +(590 +) +— +— +— +(590 +) +— +(590 +) +Issuance of common stock to Board members and advisors +30 +— +— +— +16 +— +— +— +16 +— +16 +Stock options expense related to equity-based awards +— +— +— +— +2,279 +— +— +— +2,279 +— +2,279 +Stock options exercised +8 +— +— +— +43 +— +— +— +43 +— +43 +Liability-based stock option awards settled +— +— +— +— +84 +— +— +— +84 +— +84 +Restricted stock issued +212 +2 +— +— +(2 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +(17 +) +— +60 +— +(17 +) +— +(17 +) +Restricted stock and restricted stock units expense +— +— +— +— +3,023 +— +— +— +3,023 +— +3,023 +Cancellation of treasury stock +(1,335 +) +(13 +) +— +— +(10,752 +) +— +(1,335 +) +10,765 +— +— +— +Capital contributed to less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +150 +150 +Current period net income (loss) +— +— +— +— +— +110,771 +— +— +110,771 +(17 +) +110,754 +Balance at December 31, 2014 +73,374 +734 +— +— +724,819 +140,855 +31 +— +866,408 +133 +866,541 +Issuance of common stock +10,329 +104 +— +— +260,148 +— +— +— +260,252 +— +260,252 +Issuance of preferred stock +— +— +150 +1 +32,489 +— +— +— +32,490 +— +32,490 +Cost to issue equity +— +— +— +— +(1,151 +) +— +— +— +(1,151 +) +— +(1,151 +) +Conversion of preferred stock to common stock +1,500 +15 +(150 +) +(1 +) +(14 +) +— +— +— +— +— +— +Stock-based compensation expense related to equity-based awards +— +— +— +— +9,333 +— +— +— +9,333 +— +9,333 +Stock options exercised +25 +— +— +— +10 +— +— +— +10 +— +10 +Liability-based stock option awards settled +25 +— +— +— +446 +— +— +— +446 +— +446 +Restricted stock issued +429 +4 +— +— +(4 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +— +— +138 +— +— +— +— +Vesting of restricted stock units +52 +1 +— +— +(1 +) +— +— +— +— +— +— +Cancellation of treasury stock +(167 +) +(2 +) +— +— +2 +— +(167 +) +— +— +— +— +Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +562 +562 +Current period net (loss) income +— +— +— +— +— +(679,785 +) +— +— +(679,785 +) +261 +(679,524 +) +Balance at December 31, 2015 +85,567 +$ +856 +— +$ +— +$ +1,026,077 +$ +(538,930 +) +2 +$ +— +$ +488,003 +$ +956 +$ +488,959 +The accompanying notes are an integral part of these financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +2015 +2014 +2013 +Operating activities +Net (loss) income +$ +(679,524 +) +$ +110,754 +$ +45,094 +Adjustments to reconcile net (loss) income to net cash provided by operating activities +Unrealized loss (gain) on derivatives +39,265 +(58,302 +) +7,232 +Depletion, depreciation and amortization +178,847 +134,737 +98,395 +Accretion of asset retirement obligations +734 +504 +348 +Full-cost ceiling impairment +801,166 +— +21,229 +Stock-based compensation expense +9,450 +5,524 +3,897 +Deferred income tax (benefit) provision +(150,327 +) +64,242 +9,293 +Amortization of debt issuance costs and discounts +852 +— +— +Net (gain) loss on asset sales and inventory impairment +(908 +) +— +192 +Changes in operating assets and liabilities +Accounts receivable +3,633 +(13,318 +) +(2,160 +) +Lease and well equipment inventory +(180 +) +(211 +) +243 +Prepaid expenses +(544 +) +(783 +) +(668 +) +Other assets +(552 +) +1,212 +(548 +) +Accounts payable, accrued liabilities and other current liabilities +1,375 +607 +(3,638 +) +Royalties payable +1,654 +6,663 +1,257 +Advances from joint interest owners +700 +— +(1,515 +) +Income taxes payable +2,405 +39 +404 +Other long-term liabilities +489 +(187 +) +415 +Net cash provided by operating activities +208,535 +251,481 +179,470 +Investing activities +Proceeds from sale of assets +139,836 +79 +— +Oil and natural gas properties capital expenditures +(432,715 +) +(560,849 +) +(363,192 +) +Expenditures for other property and equipment +(64,499 +) +(9,152 +) +(3,977 +) +Business combination, net of cash acquired +(24,028 +) +— +— +Maturities of certificates of deposit, net of purchases +— +— +230 +Restricted cash +(43,098 +) +— +— +Restricted cash in less-than-wholly-owned subsidiaries +(650 +) +(609 +) +— +Net cash used in investing activities +(425,154 +) +(570,531 +) +(366,939 +) +Financing activities +Repayments of borrowings +(476,982 +) +(180,000 +) +(130,000 +) +Borrowings under Credit Agreement +125,000 +320,000 +180,000 +Proceeds from issuance of common stock +188,720 +181,875 +149,069 +Proceeds from issuance of senior unsecured notes +400,000 +— +— +Cost to issue equity +(1,158 +) +(590 +) +(7,390 +) +Cost to issue senior unsecured notes +(9,598 +) +— +— +Proceeds from stock options exercised +10 +43 +— +Capital commitment from non-controlling interest owners of less-than-wholly-owned subsidiaries +562 +150 +— +Taxes paid related to net share settlement of stock-based compensation +(1,610 +) +(308 +) +(18 +) +Net cash provided by financing activities +224,944 +321,170 +191,661 +Increase in cash +8,325 +2,120 +4,192 +Cash at beginning of year +8,407 +6,287 +2,095 +Cash at end of year +$ +16,732 +$ +8,407 +$ +6,287 +Supplemental disclosures of cash flow information (Note 14) +The accompanying notes are an integral part of these financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2015, 2014 and 2013 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”) 810. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +The Company has only one reportable operating segment, which is oil and natural gas exploration and production. The Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. Although the Company’s midstream operations have increased in significance during 2015, as of December 31, 2015, the midstream operations do not meet any of the thresholds which would require segment reporting. +Reclassifications +Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. +Change in Accounting Principles +The Company adopted Accounting Standards Update (“ASU”) 2015-03, Interest - Imputation of Interest (Subtopic 935-30): Simplifying the Presentation of Debt Issuance Costs , effective June 30, 2015. This standard requires companies that have historically presented debt issuance costs as an asset to present those costs as a direct deduction from the carrying amount of the underlying debt liability. To the extent that there are no borrowings under the Credit Agreement (as defined in Note 6), the related deferred loan costs will continue to be classified as an asset. The guidance required retrospective application in the financial statements. As such, the Company reclassified $1.8 million at December 31, 2014 related to deferred loan costs for the Credit Agreement which had previously been presented in “Prepaid expenses and other assets.” As the Company had no borrowings outstanding under the Credit Agreement at December 31, 2015 , approximately $1.8 million of deferred loan costs related to the Credit Agreement are included in “Prepaid expenses and other assets.” The Company’s senior unsecured notes are presented net of approximately $8.7 million of deferred loan costs at December 31, 2015 . The Company had no senior unsecured notes outstanding at December 31, 2014 . +The Company also adopted ASU 2015-17, Income Taxes (Topic 740) , effective December 31, 2015. This standard requires deferred income tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. The standard permitted either prospective or retrospective application. The Company elected to apply the standard retrospectively. As such, the Company reclassified approximately $19.8 million of “Deferred income taxes” from current to noncurrent on the consolidated balance sheet as of December 31, 2014. As the Company recorded a valuation allowance against all of the Company’s deferred tax assets as of December 31, 2015 (as described in Note 7), adoption of this standard had no impact on the consolidated balance sheet as of December 31, 2015. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Restricted Cash +Restricted cash represents a portion of the cash paid for the Loving County System by EnLink (as described in Note 5) directly to a qualified intermediary to facilitate like-kind-exchange transactions for federal income tax purposes as well as cash held by the Company’s less-than-wholly-owned subsidiaries. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions and, in January 2016, the remaining balance of $42.1 million was returned to the Company by the qualified intermediary to be used for general corporate purposes. By contractual agreement, the cash in the account held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ — Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future well operations or equipment held for sale. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $6.9 million , $6.4 million and $3.7 million of its general and administrative costs in 2015 , 2014 and 2013 , respectively. The Company capitalized $3.9 million , $2.8 million and $1.9 million of its interest expense for the years ended December 31, 2015, 2014 and 2013 , respectively. +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per barrel and $2.59 per MMBtu, respectively. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per barrel and $4.35 per MMBtu, respectively. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.67 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +For the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $801.2 million , exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). +During the year ended December 31, 2014 , the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2014 . +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +During the year ended December 31, 2013, the Company recorded an impairment charge of $21.2 million , exclusive of tax effect, to its net capitalized costs. This charge is reflected in the Company’s consolidated statement of operations for the year ended December 31, 2013. +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Other Property and Equipment +Other property and equipment are recorded at historical cost. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 10 years) using the straight-line method. Midstream support equipment and facilities include the Company’s pipelines, processing facilities and salt water disposal systems and are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under Revenues in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments. +Revenue Recognition +The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. +For the year ended December 31, 2015 , the Company had three significant purchasers that accounted for approximately 59% of its total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2014 and 2013 , the Company had three and five significant purchasers that accounted for approximately 68% and 87% , respectively, of its total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2015, 2014 and 2013 , approximately 39% , 44% and 81% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Stock-Based Compensation +The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock. +The Company utilizes the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units. +The Company’s consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 include a stock-based compensation (non-cash) expense of $9.5 million , $5.5 million and $3.9 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.9 million , $0.3 million and $0.3 million in 2015 , 2014 and 2013 , respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2015, 2014 and 2013 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income tax for the years ended December 31, 2015, 2014 and 2013 . +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2015, 2014 and 2013 (in thousands, except per share data). +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Year Ended December 31, +2015 +2014 +2013 +Net (loss) income attributable to Matador Resources Company shareholders — numerator +$ +(679,785 +) +$ +110,771 +$ +45,094 +Weighted average common shares outstanding — denominator +Basic +81,537 +70,229 +58,777 +Dilutive effect of options, restricted stock units and preferred shares +— +677 +152 +Diluted weighted average common shares outstanding +81,537 +70,906 +58,929 +Earnings (loss) per common share attributable to +Matador Resources Company shareholders +Basic +$ +(8.34 +) +$ +1.58 +$ +0.77 +Diluted +$ +(8.34 +) +$ +1.56 +$ +0.77 +A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2015 are with The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s Credit Agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Recognition and Measurement of Financial Assets and Financial Liabilities . In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements. +Revenue from Contracts with Customers . In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements. +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2015 and 2014 (in thousands). +December 31, +2015 +2014 +Oil and natural gas properties +Evaluated (subject to amortization) +$ +2,122,174 +$ +1,617,913 +Unproved and unevaluated (not subject to amortization) +387,504 +264,419 +Total oil and natural gas properties +2,509,678 +1,882,332 +Accumulated depletion +(1,574,040 +) +(596,218 +) +Net oil and natural gas properties +935,638 +1,286,114 +Other property and equipment +Midstream support equipment and facilities +78,564 +38,135 +Furniture, fixtures and other equipment +2,918 +2,633 +Software +2,193 +1,733 +Land +1,539 +— +Leasehold improvements +1,173 +971 +Total other property and equipment +86,387 +43,472 +Accumulated depreciation +(9,619 +) +(7,514 +) +Net other property and equipment +76,768 +35,958 +Net property and equipment +$ +1,012,406 +$ +1,322,072 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2015 and the year in which these costs were incurred (in thousands). +Description +2015 +2014 +2013 +2012 and prior +Total +Costs incurred for +Property acquisition +$ +238,436 +$ +68,207 +$ +41,800 +$ +672 +$ +349,115 +Exploration wells +14,650 +30 +— +— +14,680 +Development wells +22,558 +1,151 +— +— +23,709 +Total +$ +275,644 +$ +69,388 +$ +41,800 +$ +672 +$ +387,504 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred which remain in unproved and unevaluated property at December 31, 2015 are related primarily to the Company’s leasehold acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past three years. These costs include, in particular, the cost of the acreage acquired as part of the HEYCO Merger (as described and defined in Note 5) in 2015. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties which are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $38.4 million at December 31, 2015 . Of this +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +total, $14.7 million was associated with exploration wells and $23.7 million was associated with development wells. The Company anticipates that most of the $38.4 million associated with these wells in progress at December 31, 2015 will be transferred to the amortization base during 2016 . +NOTE 4 — ASSET RETIREMENT OBLIGATIONS +In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2015 and 2014 (in thousands). +Year Ended December 31, +2015 +2014 +Beginning asset retirement obligations +$ +11,951 +$ +7,484 +Liabilities incurred during period +4,508 +2,322 +Liabilities settled during period +(588 +) +(22 +) +Revisions in estimated cash flows +(1,185 +) +1,663 +Accretion expense +734 +504 +Ending asset retirement obligations +15,420 +11,951 +Less: current asset retirement obligations (1) +(254 +) +(311 +) +Long-term asset retirement obligations +$ +15,166 +$ +11,640 +__________________ +(1) +Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2015 and 2014 . +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES +Business Combinations +On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross ( 18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks prospect areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction. +As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Matador incurred an additional $4.5 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. As a result of the HEYCO Merger, Matador incurred deferred tax liabilities of approximately $76.8 million and assumed other liabilities of approximately $4.5 million . The HEYCO Merger was accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +During the year ended December 31, 2015 , the Company incurred approximately $2.5 million of transaction costs associated with the HEYCO Merger, which were included in “General and administrative” costs in the consolidated statement of operations. The majority of the assets acquired in the HEYCO Merger were in the form of non-producing acreage. The producing wells acquired in the HEYCO Merger did not have a material impact on the Company’s revenues or results of operations for the year ended December 31, 2015 . +The preliminary allocation of the consideration given related to this business combination was as follows (in thousands). The Company anticipates that the allocation of the consideration given will be finalized during the first quarter of 2016 upon determination of the final customary purchase price adjustments. +Consideration given +Allocation +Cash +$ +26,148 +Preferred shares issued +32,490 +Common shares issued +71,478 +Total consideration given +$ +130,116 +Allocation of purchase price +Cash acquired +$ +626 +Accounts receivable +3,542 +Inventory +180 +Other current assets +106 +Oil and natural gas properties +Evaluated oil and natural gas properties +16,524 +Unproved oil and unevaluated natural gas properties +202,310 +Other property and equipment +178 +Accounts payable +(2,034 +) +Accrued liabilities +(495 +) +Current note payable +(11,982 +) +Asset retirement obligations +(2,046 +) +Deferred tax liabilities incurred +(76,793 +) +Net assets acquired +$ +130,116 +Divestitures +On October 1, 2015 , the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Processing Plant. +Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and the Company received net proceeds of approximately $139.8 million , after deducting customary purchase price adjustments of approximately $3.6 million . In conjunction with the sale of the Loving County System, the Company dedicated its leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement. +Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and will be recognized as a gain on asset sales over the 15 -year term of the gathering and processing agreement. As such, the Company recognized a gain on the +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +sale for the year ended December 31, 2015 of $1.1 million in the consolidated statement of operations, with $4.8 million remaining as a current deferred gain, representing the gain expected to be recognized in 2016, and $102.5 million remaining as noncurrent deferred gain on the consolidated balance sheet as of December 31, 2015 . Should certain events occur in the future that cause a redetermination of whether the sale is required to be accounted for as a sale and leaseback transaction, the remaining deferred gain would be recognized prior to the completion of the agreement. Such events could include EnLink’s construction or acquisition of another plant that could process the Company’s natural gas, as permitted by the gathering and processing agreement, or the Company’s determination that future production would not be sufficient to fully utilize the capacity of the plant whereby the Company elects to lower its committed volumes to be processed at the plant. +The Company can, at its option, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. +NOTE 6 — DEBT +Credit Agreement +On September 28, 2012 , the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million . MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the second quarter of 2015 , the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2014 , and as a result, on April 6, 2015 , the Company received notice that the borrowing base would be reaffirmed at $450.0 million and the conforming borrowing base would be reaffirmed at $375.0 million . Pursuant to an amendment to the Credit Agreement entered into concurrently with the issuance of $400.0 million of senior unsecured notes on April 14, 2015 discussed herein, the borrowing base was reduced to the conforming borrowing base of $375.0 million . During October 2015, the lenders completed their review of the Company’s estimated total proved oil and natural gas reserves at June 30, 2015, and as a result the Company amended the Credit Agreement to reaffirm the borrowing base at $375.0 million and extend the maturity date to October 16, 2020. This October 2015 redetermination constituted the regularly scheduled November 1 redetermination. +In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. Total deferred loan costs were $1.8 million at December 31, 2015 , and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +At December 31, 2015 , the Company had no borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. During the year ended December 31, 2015 using a portion of the net proceeds from the senior unsecured notes offering and public offering of our common stock discussed herein, the Company repaid a total of $465.0 million of its outstanding borrowings under the Credit Agreement. At February 25, 2016 , the Company continued to have no borrowings outstanding under the Credit Agreement and approximately $0.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 6 — DEBT — Continued +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. +A commitment fee of 0.375% to 0.50% , depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of the Company’s assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; and +• +engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and +• +take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving the Company or its subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +At December 31, 2015 , the Company believes that it was in compliance with the terms of its Credit Agreement. +Senior Unsecured Notes +On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes are Matador’s senior unsecured obligations, are redeemable as described below and were issued at par value. The net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Original Notes mature on April 15, 2023 , and interest is payable semi-annually in arrears on April 15 and October 15 of each year. +On October 21, 2015, and pursuant to a registered exchange offer, the Company exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes” or the “Notes”). The terms of such Notes are substantially the same as the terms of the Original Notes +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 6 — DEBT — Continued +except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Notes. +On or after April 15, 2018 , Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve month period beginning on April 15 of the years indicated. +Year +Redemption Price +2018 +105.156% +2019 +103.438% +2020 +101.719% +2021 and thereafter +100.000% +At any time prior to April 15, 2018 , Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. +In addition, at any time prior to April 15, 2018 , Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the indenture governing the Notes (the “Indenture”)) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date. +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company; +• +consolidate, merge or transfer all or substantially all of its assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• +default for 30 days in the payment when due of interest on the Notes; +• +default in the payment when due of the principal of, or premium, if any, on the Notes; +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 6 — DEBT — Continued +• +failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets; +• +failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture; +• +failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture; +• +payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more; +• +failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; +• +any subsidiary guarantee by a guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• +certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +Note Payable +In connection with the HEYCO Merger, the Company assumed a note payable to PlainsCapital Bank in the amount of $12.5 million pursuant to which approximately $12.0 million of indebtedness was outstanding. The outstanding indebtedness was repaid on April 14, 2015 using a portion of the net proceeds from the Notes offering, and the related credit agreement and all associated obligations were terminated. +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 7 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2015 and 2014 , respectively, is as follows (in thousands). +December 31, +2015 +2014 +Deferred tax assets +Net operating loss carryforwards +$ +79,208 +$ +88,447 +Alternative minimum tax carryforward +9,785 +7,197 +Percentage depletion carryover +2,442 +2,068 +Property and equipment +42,757 +113 +Deferred gain on sale leaseback transaction +32,831 +— +Other +7,396 +281 +Total deferred tax assets +174,419 +98,106 +Valuation allowance on deferred tax assets +(154,320 +) +— +Total deferred tax assets, net of valuation allowance +20,099 +98,106 +Deferred tax liabilities +Unrealized gain on derivatives +(5,699 +) +(20,145 +) +Property and equipment +— +(145,620 +) +Other +(14,400 +) +(5,875 +) +Total deferred tax liabilities +(20,099 +) +(171,640 +) +Net deferred tax liabilities +$ +— +$ +(73,534 +) +The Company reported a net loss for the year ended December 31, 2015 . The Company had an effective tax rate of 36.8% for the year ended December 31, 2014 . Total income tax expense for the year ended December 31, 2014 differed from amounts computed by applying the U.S. federal statutory rates to pre-tax income primarily due to the impact of state income taxes. +At December 31, 2015 , the Company had net operating loss carryforwards of $212.5 million for federal income tax purposes and $4.8 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the state of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . +As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the year ended December 31, 2015 , the Company recorded an impairment charge of $801.2 million , exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2015 , the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded; as a result, the Company established a valuation allowance of $154.3 million against the Company’s federal and state deferred tax assets. The valuation allowance will continue to be recognized until the realization of future tax benefits are more likely than not to be utilized. +No impairment to the net carrying value of the Company’s oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the year ended December 31, 2014 . +At March 31, 2013, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $21.2 million , exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. This charge is reflected in the Company’s consolidated statement of operations for the year ended December 31, 2013. +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 7 — INCOME TAXES — Continued +The income tax expense reconciled to the tax computed at the statutory federal rate for the years ended December 31, 2015, 2014 and 2013 , respectively, is as follows (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Current income tax provision +State income tax +$ +371 +$ +— +$ +— +Federal alternative minimum tax +2,588 +133 +404 +Net current income tax provision +2,959 +133 +404 +Deferred income tax provision (benefit) +Federal tax expense at statutory rate (1) +(289,412 +) +61,301 +19,177 +State income tax +(13,215 +) +2,707 +431 +Permanent differences (2) +698 +397 +319 +Federal alternative minimum tax +(2,588 +) +(133 +) +(404 +) +Change in federal valuation allowance +145,777 +— +(8,885 +) +Change in state valuation allowance +8,413 +(30 +) +(1,345 +) +Net deferred income tax (benefit) provision +(150,327 +) +64,242 +9,293 +Total income tax (benefit) provision +$ +(147,368 +) +$ +64,375 +$ +9,697 +__________________ +(1) +The statutory federal tax rate was 35% for the years ended December 31, 2015, 2014 and 2013 . +(2) +Amount is primarily attributable to stock-based compensation. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the state of New Mexico and the state of Louisiana tax returns is 2012 . The earliest tax year open for examination by the state of Texas is 2009. During the year ended December 31, 2015 , the Company’s 2009 and 2010 franchise tax returns were under examination by the state of Texas. This examination has been completed with no additional tax due; however, the examination has not been formally closed. In addition, as of December 31, 2015, the Company’s 2013 federal income tax return was under examination by the Internal Revenue Service. This examination is in the preliminary stage and no additional income taxes or refunds of previous tax payments for 2013 had been recorded as a result of this examination at December 31, 2015. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2015 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 8 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. +In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan provided for a maximum of 4,000,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The 2012 Incentive Plan was amended and restated and approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 10, 2015. Among other things, this amendment increased the maximum number of shares of common stock issuable by the Company pursuant to grants of awards to 8,700,000 . The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. +The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Nominating, Compensation and Planning Committee, determines the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period. +Stock Options +Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five or ten years. +The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2015, 2014 and 2013 . +2015 +2014 +2013 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +0.39 years +1.51 years +2.44 years +Risk-free interest rate +0.64% +0.74% +0.69% +Volatility +91.98% +55.14% +51.51% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +—% +—% +0.79% +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2015, 2014 and 2013 . +2015 +2014 +2013 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +4.00 years +3.99 years +4.00 years +Risk-free interest rate +1.15% +1.21% +0.69% +Volatility +56.89% +51.47% +58.65% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +3.21% +4.28% +6.37% +Weighted average fair value of stock option awards granted during the year +$9.90 +$9.45 +$3.91 +The Company estimated the future volatility of its common stock using the historical value of its peer group for a period of time commensurate with the expected term of the stock option due to the lack of historical trading data available for its common stock. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2015 under the 2003 Plan and the 2012 Incentive Plan is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2014 +1,798 +$ +12.47 +Options granted +797 +$ +22.32 +Options exercised +(85 +) +$ +9.32 +Options forfeited +(147 +) +$ +20.55 +Options outstanding at December 31, 2015 +2,363 +$ +15.40 +Options outstanding at +December 31, 2015 +Options exercisable at +December 31, 2015 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life +Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$8.18 - $9.90 +848 +2.31 +$ +8.33 +432 +$ +8.41 +$10.39 - $17.80 +394 +1.35 +$ +10.64 +197 +$ +10.64 +$18.77 - $22.66 +837 +3.95 +$ +21.83 +5 +$ +18.77 +$23.40 - $27.33 +284 +3.26 +$ +24.22 +— +$ +— +At December 31, 2015 , the aggregate intrinsic value was $13.3 million for outstanding options and $6.7 million for exercisable options, based on the Company’s quoted closing market price of $19.77 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2015 was 2.21 years. +The total intrinsic value of options exercised during the years ended December 31, 2015, 2014 and 2013 was $1.3 million , $0.2 million and $36,000 , respectively. The tax related benefit realized from the exercise of stock options totaled $0.3 million , $0.1 million and zero for the years ended December 31, 2015, 2014 and 2013 , respectively. +During the years ended December 31, 2015, 2014 and 2013 , the Company recognized $4.7 million , $2.5 million and $2.2 million , respectively, in stock-based compensation expense attributable to stock options. At December 31, 2015, 2014 and 2013 , the Company had recorded zero , $1.4 million and $1.2 million of long-term liabilities and $1.0 million , zero and $0.1 +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +million of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2015, 2014 and 2013 , respectively. +At December 31, 2015 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $8.5 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.81 years. +The fair value of options vested during 2015 , 2014 and 2013 was $1.3 million , $1.5 million and $0.3 million , respectively. +Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a term no longer than two years after vesting. No such elections were made with respect to the 2012 restricted stock unit awards; one current director elected to defer the issuance of his awards in 2014 and 2013. All awards granted in 2015, 2014 and 2013 were service based awards and vest over the service period which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2015 were granted under the 2012 Incentive Plan. +Restricted stock awards granted in 2012 included 116,841 shares of performance based restricted stock and 116,841 performance based restricted stock units with a combined weighted average fair value of $13.24 per combined share and unit. These awards vested based on the outcome of the Company’s total shareholder return over a three-year period beginning March 19, 2012 and ending April 15, 2015 as compared to a designated peer group. These awards resulted in the vesting of an aggregate of 96,590 shares of restricted stock in addition to 96,590 restricted stock units. The remaining shares of restricted stock and restricted stock units were forfeited. +A summary of the non-vested restricted stock and restricted stock units as of December 31, 2015 is presented below (in thousands, except fair value). +Restricted Stock +Restricted Stock Units +Service Based +Performance Based +Service Based +Performance Based +Non-vested restricted stock and +restricted stock units +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value (1) +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value (1) +Non-vested at +December 31, 2014 +569 +$ +14.03 +97 +$ +13.24 +71 +$ +16.28 +97 +$ +— +Granted +430 +$ +22.51 +— +— +36 +$ +24.58 +— +— +Vested +(8 +) +$ +15.03 +(97 +) +— +(39 +) +$ +14.02 +(97 +) +— +Forfeited +(137 +) +$ +18.08 +— +— +— +— +— +— +Non-vested at +December 31, 2015 +854 +$ +17.64 +— +$ +13.24 +68 +$ +21.89 +— +$ +— +__________________ +(1) +The fair value of these restricted stock units is reflected in the fair value of the performance based restricted stock, which was estimated based on the most likely outcome of the award as determined by the Monte Carlo method. +At December 31, 2015 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $18.2 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the stock price on December 31, 2015 . +During the years ended December 31, 2015, 2014 and 2013 , the Company recognized approximately $4.7 million , $3.0 million and $1.6 million , respectively, in stock-based compensation expense attributable to restricted stock and restricted stock units. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +At December 31, 2015 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $10.3 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.6 years. +The fair value of restricted stock and restricted stock units vested during 2015 , 2014 and 2013 was $0.8 million , $0.9 million and $0.2 million , respectively. +The total tax benefit recognized for all stock-based compensation was $3.4 million , $1.9 million and $1.1 million for the years ended December 31, 2015, 2014 and 2013 , respectively. +In February 2016 , the Company granted awards of 243,428 shares of restricted stock and options to purchase 608,287 shares of the Company’s common stock at an exercise price of $15.00 per share to certain of its employees. The fair value of these awards was approximately $7.0 million. All of these awards cliff vest in three years. +NOTE 9 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled approximately $0.6 million , $0.4 million and $0.2 million in 2015 , 2014 and 2013 , respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $0.8 million , $0.5 million and $0.3 million in 2015 , 2014 and 2013 , respectively. The Company made no additional discretionary contributions in any reporting period presented. +NOTE 10 — EQUITY +Stock Offerings, Retirement and Issuances +As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. +On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 1,250,000 of the 1,500,000 shares were being held in escrow at December 31, 2015 to satisfy the post-closing adjustments to the merger consideration for title or environmental defects on the properties acquired in the merger. +On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million , the Company received net proceeds of approximately $187.6 million . The Company used a portion of the net proceeds to repay $85.0 million in outstanding borrowings under the Credit Agreement (see Note 6), which amounts may be reborrowed in accordance with the terms of that facility. The remaining $102.6 million of net proceeds was used to fund a portion of the Company’s working capital expenditures, including the addition of a third drilling rig in the Delaware Basin in late July 2015 and targeted acquisitions of additional acreage in the Delaware Basin, as well as in the Eagle Ford shale and the Haynesville shale, and for other general working capital needs. +On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting direct offering costs totaling approximately $0.6 million , the Company received net proceeds of approximately $181.3 million . +On September 10, 2013, the Company completed an underwritten public offering of 9,775,000 shares of its common stock, including 1,275,000 shares issued pursuant to the underwriters’ exercise of their option to purchase additional shares. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 10 — EQUITY— Continued +After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million , the Company received net proceeds of approximately $141.7 million . +Treasury Stock +On October 30, 2015 and October 31, 2014, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2015 and September 30, 2014, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The 2,586 and 30,967 shares of treasury stock outstanding at December 31, 2015 and December 31, 2014, respectively, and the increase of 105,126 shares in treasury stock outstanding during the year ended December 31, 2013, represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments typically consist of put and call options in the form of costless collars or swap contracts. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +The Company has entered into various costless collar contracts to mitigate its exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to any oil contract is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. +When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +At December 31, 2015 , the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2016. +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2015 . +Notional Quantity (Bbl or MMBtu) +Weighted Average Price Floor ($/Bbl or +$/MMBtu) +Weighted Average Price Ceiling ($/Bbl or +$/MMBtu) +Fair Value of Asset (thousands) +Commodity +Calculation Period +Oil +01/01/2016 - 12/31/2016 +1,560,000 +$ +47.46 +$ +74.64 +$ +13,083 +Natural Gas +01/01/2016 - 12/31/2016 +8,400,000 +$ +2.75 +$ +3.80 +3,201 +Total open derivative financial instruments +$ +16,284 +Subsequent to December 31, 2015, the Company entered into various costless collar contracts for oil and natural gas. The costless collar contracts for oil included approximately 600,000 Bbl in 2016 with a weighted average floor price of $35.00 per Bbl and a weighted average ceiling price of $43.23 per Bbl. The Company also entered into costless collar contracts for natural gas, which included approximately 3,300,000 MMBtu in 2016, with a weighted average floor price of $2.25 per MMBtu and a weighted average ceiling price of $2.90 per MMBtu, and approximately 7,200,000 MMBtu in 2017, with a weighted average floor price of $2.25 MMBtu and a weighted average ceiling price of $3.57 MMBtu. +These derivative financial instruments are subject to master netting arrangements; all but one counterparty allow for cross-commodity master netting provided the settlements dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2015 and December 31, 2014 (in thousands). +Derivative Instruments +Gross amounts recognized +Gross amounts netted in the consolidated balance sheets +Net amounts presented in the consolidated balance sheets +December 31, 2015 +Current assets +$ +16,767 +$ +(483 +) +$ +16,284 +Other assets +— +— +— +Current liabilities +(483 +) +483 +— +Other liabilities +— +— +— +Total +$ +16,284 +$ +— +$ +16,284 +December 31, 2014 +Current assets +$ +56,255 +$ +(706 +) +$ +55,549 +Other assets +— +— +— +Current liabilities +(706 +) +706 +— +Other liabilities +— +— +— +Total +$ +55,549 +$ +— +$ +55,549 +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. +Location in +Year Ended December 31, +Type of Instrument +Statement of Operations +2015 +2014 +2013 +Derivative Instrument +Oil +Revenues: Realized gain (loss) on derivatives +$ +62,259 +$ +5,221 +$ +(2,408 +) +Natural Gas +Revenues: Realized gain (loss) on derivatives +12,653 +(718 +) +831 +Natural Gas Liquids (NGL) +Revenues: Realized gain on derivatives +2,182 +519 +668 +Realized gain (loss) on derivatives +77,094 +5,022 +(909 +) +Oil +Revenues: Unrealized (loss) gain on derivatives +(31,897 +) +47,178 +(5,319 +) +Natural Gas +Revenues: Unrealized (loss) gain on derivatives +(5,440 +) +9,087 +(1,580 +) +Natural Gas Liquids (NGL) +Revenues: Unrealized (loss) gain on derivatives +(1,928 +) +2,037 +(333 +) +Unrealized (loss) gain on derivatives +(39,265 +) +58,302 +(7,232 +) +Total +$ +37,829 +$ +63,324 +$ +(8,141 +) +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 12 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 +Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 +Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 +Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +At December 31, 2015 and 2014 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities. +At December 31, 2015 and 2014 , the carrying value of borrowings under the Credit Agreement approximates fair value as it is subject to short-term floating interest rates that reflect market rates available to the Company at the time and is classified at Level 2. +At December 31, 2015, the fair value of the Company’s Notes was $381.0 million based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy. The Company had no Notes outstanding at December 31, 2014. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2015 and 2014 (in thousands). +Fair Value Measurements at +December 31, 2015 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil and natural gas derivatives +$ +— +$ +16,284 +$ +— +$ +16,284 +Total +$ +— +$ +16,284 +$ +— +$ +16,284 +Fair Value Measurements at +December 31, 2014 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil and natural gas derivatives +$ +— +$ +55,549 +$ +— +$ +55,549 +Total +$ +— +$ +55,549 +$ +— +$ +55,549 +Additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 12 — FAIR VALUE MEASUREMENTS — Continued +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination (see Note 5), lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2015 and 2014 . The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions. +NOTE 13 — COMMITMENTS AND CONTINGENCIES +Office Lease +The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. In June 2015 , the Company entered into the seventh amendment to its office lease agreement. This amendment increased the square footage of its corporate headquarters to approximately 100,000 square feet effective January 1, 2016 . The lease expires during 2026 . The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease. +From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties. +The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2015 (in thousands). +Year Ending December 31, +Amount +2016 +$ +2,017 +2017 +2,432 +2018 +2,488 +2019 +2,528 +2020 +2,602 +Thereafter +14,995 +Total +$ +27,062 +Rent expense, including fees for operating expenses and consumption of electricity, was $1.7 million , $0.9 million and $0.8 million for 2015 , 2014 and 2013 , respectively. +Natural Gas and NGL Processing and Transportation Commitments +Effective September 1, 2012 , the Company entered into a firm five -year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid approximately $5.5 million and $5.8 million in processing and transportation fees under this agreement during the years ended December 31, 2015 and 2014 , respectively. The future undiscounted minimum payments under this agreement as of December 31, 2015 are $1.8 million in 2016 and $1.2 million in 2017. +As part of the sale of the Loving County System (see Note 5), the Company entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued +processing at the counterparty’s facility. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facility in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the transportation and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2015 , the total deficiency fee required to be paid would be approximately $9.6 million . In addition, if the Company elects to reduce the transportation and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed transportation and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $1.8 million in processing and transportation fees under this agreement during the year ended December 31, 2015 . The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plant or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plant. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for one year or less, although the Company has entered into longer-term contracts in order to secure new drilling rigs equipped with the latest technology in plays that were until recently experiencing heavy demand for drilling rigs. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $43.5 million at December 31, 2015 . +The Company entered into an agreement with a third party for the engineering, procurement, construction and installation of a natural gas processing plant in the Rustler Breaks prospect area in Eddy County, New Mexico in late 2015 . This plant is expected to process a portion of the Company’s natural gas produced from certain of its wells in the Delaware Basin, as well as third-party natural gas once the plant is completed. Total commitments under this contract are $28.5 million and the Company made payments totaling $7.0 million during the year ended December 31, 2015 . The plant is scheduled to be completed and placed in service in the third quarter of 2016. +At December 31, 2015 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $5.7 million at December 31, 2015 . The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a defendant in several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 14 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2015 and 2014 (in thousands). +December 31, +2015 +2014 +Accrued evaluated and unproved and unevaluated property costs +$ +54,586 +$ +86,259 +Accrued support equipment and facilities costs +17,393 +4,290 +Accrued lease operating expenses +7,743 +9,034 +Accrued interest on debt +5,806 +206 +Accrued asset retirement obligations +254 +311 +Accrued partners’ share of joint interest charges +4,565 +3,767 +Other +2,022 +3,489 +Total accrued liabilities +$ +92,369 +$ +107,356 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Cash paid for interest expense, net of amounts capitalized +$ +16,154 +$ +5,269 +$ +5,801 +Asset retirement obligations related to mineral properties +2,510 +3,843 +1,363 +Asset retirement obligations related to support equipment and facilities +383 +120 +3 +(Decrease) increase in liabilities for oil and natural gas properties capital expenditures +(30,683 +) +32,972 +7,458 +Increase in liabilities for support equipment and facilities +12,076 +4,290 +660 +Issuance of restricted stock units for Board and advisor services +584 +444 +274 +Issuance of common stock for Board and advisor services +24 +16 +57 +Stock-based compensation expense recognized as liability +79 +223 +1,012 +Transfer of inventory to oil and natural gas properties +615 +216 +343 +NOTE 15 — SUBSIDIARY GUARANTORS +Matador filed a registration statement on Form S-3 with the SEC in 2013, which became effective on May 9, 2013, and a registration statement on Form S-3 with the SEC in 2014, which became effective upon filing on May 22, 2014, registering, in each case, among other securities, senior and subordinated debt securities and guarantees of debt securities by certain subsidiaries of Matador (the “Shelf Guarantor Subsidiaries”). On April 14, 2015, the Company issued the Original Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Notes Guarantor Subsidiaries” and, together with the Shelf Guarantor Subsidiaries, the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). On June 1, 2015, Matador filed a registration statement on Form S-4 with the SEC in connection with the exchange of the Original Notes for the Registered Notes, including guarantees by each of the Notes Guarantor Subsidiaries. The Form S-4 was declared effective by the SEC on September 16, 2015. The Company completed the exchange of all the Original Notes for Registered Notes on October 21, 2015. At December 31, 2015 , the Guarantor Subsidiaries are 100% owned by Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries are minor. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2015, 2014 and 2013 +NOTE 16 — RELATED PARTY TRANSACTIONS +In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2015 , the Company had contributed an aggregate of approximately $0.7 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. +Additionally, substantially all of the oil production from the wells acquired in the HEYCO Merger was subject to pre-existing sales contracts with an entity owned by affiliates of HEYCO Energy Group, Inc. The Company recorded revenue of $1.1 million for oil sold pursuant to such contracts for the year ended December 31, 2015 . Such contracts were terminated in the third quarter of 2015. +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Property acquisition costs +Proved +$ +16,524 +$ +2,728 +$ +176 +Unproved and unevaluated +253,923 +78,484 +64,305 +Exploration costs +122,495 +156,178 +99,104 +Development costs (1) +305,495 +372,982 +209,956 +Total costs incurred +$ +698,437 +$ +610,372 +$ +373,541 +__________________ +(1) +Includes midstream-related development costs of approximately $77.9 million for the year ended December 31, 2015. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2015, 2014 and 2013 , most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and installing production facilities. +Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $3.3 million , $4.0 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $6.9 million , $6.4 million and $3.7 million of these internal costs in 2015 , 2014 and 2013 , respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $3.9 million , $2.8 million and $1.9 million of its interest expense for the years ended December 31, 2015 , 2014 and 2013 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2015, 2014 and 2013 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per barrel and $2.59 per MMBtu, respectively. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per barrel and $4.35 per MMBtu, respectively. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.67 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2012 +10,485 +80,007 +23,819 +Revisions of prior estimates +(199 +) +78,812 +12,936 +Purchases of minerals in-place +— +170 +28 +Extensions and discoveries +8,209 +66,121 +19,231 +Production +(2,133 +) +(12,915 +) +(4,285 +) +Total at December 31, 2013 +16,362 +212,195 +51,729 +Revisions of prior estimates +(1,196 +) +164 +(1,169 +) +Purchases of minerals in-place +10 +433 +82 +Extensions and discoveries +12,328 +69,566 +23,921 +Production +(3,320 +) +(15,303 +) +(5,870 +) +Total at December 31, 2014 +24,184 +267,055 +68,693 +Revisions of prior estimates +(2,609 +) +(75,433 +) +(15,181 +) +Purchases of minerals in-place +1,102 +2,927 +1,589 +Extensions and discoveries +27,459 +70,054 +39,135 +Production +(4,492 +) +(27,702 +) +(9,109 +) +Total at December 31, 2015 +45,644 +236,901 +85,127 +Proved Developed Reserves +December 31, 2012 +4,764 +54,040 +13,771 +December 31, 2013 +8,258 +53,458 +17,168 +December 31, 2014 +14,053 +102,795 +31,185 +December 31, 2015 +17,129 +101,447 +34,037 +Proved Undeveloped Reserves +December 31, 2012 +5,721 +25,967 +10,048 +December 31, 2013 +8,104 +158,737 +34,561 +December 31, 2014 +10,131 +164,260 +37,508 +December 31, 2015 +28,515 +135,454 +51,090 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2015, 2014 and 2013 . +The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from 68,693 MBOE at December 31, 2014 . The Company’s proved oil and natural gas reserves increased by 25,543 MBOE and the Company produced 9,109 MBOE during the year ended December 31, 2015 , resulting in a net increase of 16,434 MBOE. An increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the removal of approximately 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015 , as well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves, primarily in the Haynesville shale in Northwest Louisiana, resulting from the decline in commodity prices during 2015. The Company also purchased minerals in-place with proved reserves of 1,589 MBOE in 2015 , primarily as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to 34,037 MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014 , primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2015 , the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately 60% proved undeveloped. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s proved oil and natural gas reserves increased to 68,693 MBOE at December 31, 2014 from 51,729 MBOE at December 31, 2013 . The Company’s proved oil and natural gas reserves increased by 22,834 MBOE and the Company produced 5,870 MBOE during the year ended December 31, 2014 , resulting in a net increase of 16,964 MBOE. An increase of 23,921 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, plus additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves decreased by 1,169 MBOE during the year as a result of revisions to previous estimates, primarily downward revisions of proved undeveloped oil reserves on certain of the Company’s undeveloped locations in the Eagle Ford shale play in South Texas in 2014 . The Company also purchased minerals in-place with proved reserves of 82 MBOE in 2014. The Company’s proved developed oil and natural gas reserves increased to 31,185 MBOE at December 31, 2014 from 17,168 MBOE at December 31, 2013 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale and in the Wolfcamp and Bone Spring plays in the Delaware Basin plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2014 , the Company’s proved reserves were made up of approximately 35% oil and 65% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 51,729 MBOE at December 31, 2013 from 23,819 MBOE at December 31, 2012 . The Company’s proved oil and natural gas reserves increased by 32,195 MBOE and the Company produced 4,285 MBOE during the year ended December 31, 2013 , resulting in a net increase of 27,910 MBOE. An increase of 19,231 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves increased by 12,936 MBOE during the year as a result of revisions to previous estimates, primarily upward revisions in the Company’s proved undeveloped natural gas reserves resulting from higher natural gas prices in 2013 . The Company also purchased minerals in-place with proved reserves of 28 MBOE in 2013. The Company’s proved developed oil and natural gas reserves increased to 17,168 MBOE at December 31, 2013 from 13,771 MBOE at December 31, 2012 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2013 , the Company’s proved reserves were made up of approximately 32% oil and 68% natural gas and were approximately 33% proved developed and 67% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2015 , the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $46.79 per barrel and $2.59 per MMBtu, respectively. For the period from January through December 2014 , the comparable average oil and natural gas prices were $91.48 per barrel and $4.35 per MMBtu, respectively. For the period from January through December 2013 , the comparable average oil and natural gas prices were $93.42 per barrel and $3.67 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and marketing costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Future cash inflows +$ +2,461,131 +$ +3,197,317 +$ +2,316,626 +Future production costs +(843,117 +) +(803,662 +) +(666,450 +) +Future development costs +(615,692 +) +(553,799 +) +(507,923 +) +Future income tax expense +(43,956 +) +(321,088 +) +(181,041 +) +Future net cash flows +958,366 +1,518,768 +961,212 +10% annual discount for estimated timing of cash flows +(429,185 +) +(605,449 +) +(382,544 +) +Standardized measure of discounted future net cash flows +$ +529,181 +$ +913,319 +$ +578,668 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Balance, beginning of period +$ +913,319 +$ +578,668 +$ +394,636 +Net change in sales and transfer prices and in production (lifting) costs related to future production +(509,901 +) +87,067 +(97,511 +) +Changes in estimated future development costs +(145,861 +) +(150,447 +) +(233,232 +) +Sales and transfers of oil and natural gas produced during the period +(184,612 +) +(283,187 +) +(209,338 +) +Purchases of reserves in place +16,321 +1,838 +176 +Net change due to extensions and discoveries +401,895 +537,472 +386,696 +Net change due to revisions in estimates of reserves quantities +(285,823 +) +(26,263 +) +260,148 +Previously estimated development costs incurred during the period +121,543 +187,459 +106,348 +Accretion of discount +82,574 +65,518 +36,184 +Other +2,029 +5,492 +(371 +) +Net change in income taxes +117,697 +(90,298 +) +(65,068 +) +Standardized measure of discounted future net cash flows +$ +529,181 +$ +913,319 +$ +578,668 +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2015 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2015 +Oil and natural gas revenues +$ +56,212 +$ +71,815 +$ +87,848 +$ +62,465 +Realized gain on derivatives +24,948 +19,862 +13,780 +18,504 +Unrealized (loss) gain on derivatives +(13,909 +) +6,733 +(23,532 +) +(8,557 +) +Expenses (1) +290,769 +367,499 +319,095 +147,217 +Other expense +5,101 +6,230 +5,367 +1,783 +(Loss) income before income taxes +(228,619 +) +(275,319 +) +(246,366 +) +(76,588 +) +Income tax provision (benefit) +1,677 +(33,305 +) +(89,350 +) +(26,390 +) +Net loss +(230,296 +) +(242,014 +) +(157,016 +) +(50,198 +) +Net income attributable to non-controlling interest in subsidiaries +(105 +) +(45 +) +(75 +) +(36 +) +Net loss attributable to +Matador Resources Company shareholders +$ +(230,401 +) +$ +(242,059 +) +$ +(157,091 +) +$ +(50,234 +) +Loss per common share attributable to Matador Resources Company shareholders +Basic +$ +(2.72 +) +$ +(2.86 +) +$ +(1.89 +) +$ +(0.68 +) +Diluted +$ +(2.72 +) +$ +(2.86 +) +$ +(1.89 +) +$ +(0.68 +) +__________________ +(1) +Expenses for December 31, September 30, June 30 and March 31, 2015 included full-cost ceiling impairment charges of $219.4 million, $285.7 million, $229.0 million and $67.1 million, respectively. +The following table presents selected unaudited quarterly financial information for 2014 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2014 +Oil and natural gas revenues +$ +93,110 +$ +96,617 +$ +99,054 +$ +78,931 +Realized gain (loss) on derivatives +10,479 +(701 +) +(2,913 +) +(1,843 +) +Unrealized gain (loss) on derivatives +50,351 +16,293 +(5,234 +) +(3,108 +) +Expenses +78,675 +65,680 +60,840 +46,723 +Other expense +1,018 +406 +1,207 +1,358 +Income before income taxes +74,247 +46,123 +28,860 +25,899 +Income tax provision +27,701 +16,504 +10,634 +9,536 +Net income +46,546 +29,619 +18,226 +16,363 +Net loss attributable to non-controlling interest in subsidiaries +17 +— +— +— +Net income attributable to +Matador Resources Company shareholders +$ +46,563 +$ +29,619 +$ +18,226 +$ +16,363 +Earnings per common share attributable to Matador Resources Company shareholders +Basic +$ +0.63 +$ +0.40 +$ +0.27 +$ +0.25 +Diluted +$ +0.63 +$ +0.40 +$ +0.26 +$ +0.25 +F-40 \ No newline at end of file diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/filing_metadata.csv b/raw/filings/0001520006/2015/0001520006-16-000245/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..3d0314d5f17d9a731f4883629284602e0916da95 --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2016-02-29,2015-12-31,2016-02-29T17:58:54.000Z,0001520006-16-000245,mtdr10-k12312015.htm,10-K,11587389,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000152000616000245/mtdr10-k12312015.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000616000245/,2015,2015,1 diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/item1.txt b/raw/filings/0001520006/2015/0001520006-16-000245/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..2489277a4a7684556e34f39377f003b015f87c27 --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/item1.txt @@ -0,0 +1,1270 @@ +Item 1. Business. +In this Annual Report on Form 10-K, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities; +• maintain our financial discipline; and +• pursue opportunistic acquisitions and divestitures. +Despite a challenging commodity price environment in 2015, the successful execution of our business strategies led to significant increases in our oil and natural gas production and proved oil and natural gas reserves in 2015. We also significantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important transactions in 2015, including our merger with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., which added substantially to our Delaware Basin acreage position, our first issuance of senior unsecured notes, an equity offering and the sale of a portion of our midstream assets in Loving County, Texas to an affiliate of EnLink Midstream Partners, LP (“EnLink”). These transactions increased our operational flexibility and further strengthened our balance sheet. +2015 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2015 , we achieved record oil, natural gas and average daily oil equivalent production. In 2015 , we produced 4.5 million Bbl of oil, an increase of 35% , as compared to 3.3 million Bbl of oil produced in 2014. We also produced 27.7 Bcf of natural gas, an increase of 81% from 15.3 billion Bcf of natural gas produced in 2014. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, including 12,306 Bbl of oil per +2 +Table of Contents +day and 75.9 MMcf of natural gas per day, an increase of 55% , as compared to 16,082 BOE per day, including 9,095 Bbl of oil per day and 41.9 MMcf of natural gas per day, for the year ended December 31, 2014 . The increase in oil production was primarily attributable to our ongoing delineation and development operations in the Delaware Basin throughout 2015, as well as our development activities in the Eagle Ford shale during early 2015 . The increase in natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production in our Elm Grove properties in Northwest Louisiana in the latter half of 2014 and throughout 2015, but also includes increased natural gas production associated with our operations in both the Delaware Basin and the Eagle Ford shale. Oil production comprised 49% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2015 , as compared to 57% for the year ended December 31, 2014 . +Increased Oil and Oil Equivalent Reserves +At December 31, 2015 , our estimated total proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, which is an increase of 24% from December 31, 2014 . The associated PV-10 of our estimated total proved oil and natural gas reserves decreased 48% to $541.6 million at December 31, 2015 from $1.04 billion at December 31, 2014 , as a result of declining oil and natural gas prices throughout 2015. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 89% to 45.6 million Bbl at December 31, 2015 from 24.2 million Bbl at December 31, 2014 . This growth in oil reserves was primarily attributable to our drilling program in the Delaware Basin during 2015 . Our proved natural gas reserves decreased 11% to 236.9 Bcf at December 31, 2015 from 267.1 Bcf at December 31, 2014 . This decrease in proved natural gas reserves was largely attributable to a decrease in our proved undeveloped natural gas reserves, principally from the reclassification of proved undeveloped natural gas reserves to contingent resources, primarily in the Haynesville shale, as a result of the decline in natural gas prices during 2015 as noted below in “— Estimated Proved Reserves.” As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by Matador or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +At December 31, 2015 , proved developed reserves included 17.1 million Bbl of oil and 101.4 Bcf of natural gas, and proved undeveloped reserves included 28.5 million Bbl of oil and 135.5 Bcf of natural gas. Proved developed reserves comprised 40% and proved oil reserves comprised 54% of our total proved oil and natural gas reserves, respectively, at December 31, 2015 . Proved developed reserves comprised 45% of our total reserves and proved oil reserves comprised 35% of our total proved oil and natural gas reserves, respectively, at December 31, 2014 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past two years, as we continued to apply there what we learned from our Eagle Ford shale, as well as from our Haynesville shale, experience. The Delaware Basin will continue to be our primary area of focus in 2016. +We completed and began producing oil and natural gas from 41 gross (25.0 net) wells in the Delaware Basin in 2015, including 27 gross (23.7 net) operated and 14 gross (1.3 net) non-operated wells. We also substantially increased our acreage position in the Delaware Basin during 2015. As a result, at December 31, 2015 our total acreage position in the Delaware Basin had increased to approximately 157,100 gross ( 88,800 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been very pleased with the initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our six main prospect areas in the Delaware Basin—the Wolf and Jackson Trust prospect areas in Loving County, Texas, the Rustler Breaks and Arrowhead prospect areas in Eddy County, New Mexico and the Ranger and Twin Lakes prospect areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin grew 3.6-fold from 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, in 2014 to an average daily oil equivalent production of 6,518 BOE per day, including 4,648 Bbl of oil per day and 11.2 MMcf of natural gas per day, in 2015 . We expect our Delaware Basin production to increase throughout 2016 as we continue the delineation and development of these properties. +During 2015 , we made significant progress in reducing drilling costs and times for both Wolfcamp and Bone Spring horizontal wells in the Delaware Basin. Our focus on improving drilling times and operational efficiencies has cut drilling +3 +Table of Contents +times by as much as 50% or more on recent Wolfcamp wells in the Wolf and Rustler Breaks prospect areas as compared to earlier wells drilled in those prospect areas. In the Wolf prospect area in Loving County, Texas, for example, Wolfcamp drilling times (spud to total depth) have been reduced from an average of 43 days in 2014 to as low as 18 days on a well drilled in late 2015. In the Rustler Breaks prospect area in Eddy County, New Mexico, where the Wolfcamp formation is shallower, Wolfcamp drilling times have been reduced from an average of 32 days in 2014 and early 2015 to as low as 15 days on recent wells drilled in late 2015. In addition, our most recent Second Bone Spring horizontal well in our Rustler Breaks prospect area was drilled from spud to total depth in 12 days, making it the fastest Second Bone Spring horizontal well we have drilled to date. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to our contracted drilling rigs, including 7,500-psi circulating systems, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and starting to drill wells in “batch” mode in some areas, particularly in the Wolf prospect area where we are in development mode. +These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, reduced overall well costs in 2015 . Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million, including production facilities and other related infrastructure. In the Rustler Breaks prospect area, we expect to drill and complete Wolfcamp wells for an average of $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure. Our most recent Second Bone Spring well in this area was drilled and completed for approximately $4.0 million on an existing multi-well pad, which is the least expensive Second Bone Spring well we have drilled thus far on our Delaware Basin acreage. These well costs are substantially reduced from those of initial wells drilled in these areas. We plan to continue to focus on improving operational efficiencies as we move closer to full development of our Delaware Basin assets. +We completed and began producing oil and natural gas from 18 gross (17.3 net) wells in the Eagle Ford shale in 2015, all in the early portion of the year, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well. During the second quarter of 2015, we concluded our drilling and completion operations in the Eagle Ford for 2015 and did not drill or complete any additional operated wells in the Eagle Ford shale for the remainder of 2015. +We did not drill any operated Haynesville shale wells during 2015, but we did participate in 22 gross (1.9 net) non-operated wells drilled in the Haynesville shale in Northwest Louisiana. The most impactful of these were the Haynesville wells drilled and completed by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove properties in southern Caddo Parish. In 2015, Chesapeake completed and placed on production nine gross (1.6 net) wells at Elm Grove. As a result of these 2015 completions and additional non-operated Haynesville wells completed and placed on production in the latter half of 2014, our Haynesville natural gas production grew 135% from 19.7 MMcf of natural gas per day in 2014 to 46.4 MMcf of natural gas per day in 2015. +Financing Arrangements +On April 14, 2015, we issued $400.0 million of 6.875% senior unsecured notes due 2023 in a private placement and, on October 21, 2015, we exchanged all of the privately placed senior notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act. On April 21, 2015, we completed a public offering of 7,000,000 shares of our common stock. After deducting offering costs totaling approximately $1.2 million , we received net proceeds of approximately $187.6 million . Finally, during the fourth quarter of 2015, the lenders party to our third amended and restated credit agreement (the “Credit Agreement”), under which we had no borrowings outstanding at December 31, 2015, reaffirmed our borrowing base at $375.0 million and extended the maturity date of the credit facility to October 16, 2020. See Note 6 to the consolidated financial statements in this Annual Report on Form 10-K for more details on each of the above items. +Acquisitions and Divestitures +On February 27, 2015, we completed a business combination pursuant to which one of our wholly-owned subsidiaries merged with HEYCO (the “HEYCO Merger”), combining certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico with our Delaware Basin operations. In the HEYCO Merger, we obtained approximately 58,600 gross ( 18,200 net) acres strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas. See Note 5 to the consolidated financial statements in this Annual Report on Form 10-K for more details on the HEYCO Merger. +We also acquired approximately 1,900 net acres contributed into two joint ventures with certain affiliates of HEYCO Energy Group, Inc. We have agreed to contribute an aggregate of approximately $14 million in exchange for a 50% interest in both entities. See Note 16 to the consolidated financial statements in this Annual Report on Form 10-K for more details on the joint ventures. +On October 1, 2015 , we completed the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County System”) to EnLink. The Loving County System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the +4 +Table of Contents +“Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects our gathering system to the Processing Plant. Pursuant to the terms of the transaction, EnLink paid cash consideration of approximately $143.4 million , excluding customary purchase price adjustments, and we dedicated our leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 5 and Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more details regarding the transaction with EnLink. +Principal Areas of Interest +Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. During 2015 , we devoted most of our efforts and most of our capital investment to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale in South Texas, although we completed our planned operated drilling and completion activities in the Eagle Ford shale for 2015 in the second quarter. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2015 , essentially all of our efforts were focused on unconventional plays. +At December 31, 2015 , our principal areas of interest consisted of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas, and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2015 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +157,133 +88,750 +256 +96.0 +3,543 +1,416.9 +47,124 +27.3 +6,518 +South Texas: +Eagle Ford (5) +39,035 +29,255 +134 +115.5 +260 +227.5 +19,015 +62.5 +10,263 +Northwest Louisiana/East Texas: +Haynesville +20,707 +13,007 +198 +18.4 +448 +109.2 +18,148 +46.3 +7,731 +Cotton Valley (6) +21,775 +19,185 +93 +58.4 +71 +50.1 +840 +100.0 +443 +Area Total (7) +26,663 +23,831 +291 +76.8 +519 +159.3 +18,988 +48.7 +8,174 +Other: +Wyoming, Utah, Idaho +75,674 +35,732 +— +— +— +— +— +— +— +Total +298,505 +177,568 +681 +288.3 +4,322 +1,803.7 +85,127 +40.0 +24,955 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2015 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2015 , these engineered drilling locations included only 118 gross (71.1 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Delaware Basin, 27 gross (26.8 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 26 gross (9.4 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formations at December 31, 2015 . +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplementary Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report on Form 10-K, which is incorporated herein by reference. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware and Avalon plays on our acreage in the Delaware Basin at December 31, 2015 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +5 +Table of Contents +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, Cimarex Energy Company, BHP Billiton, Mewbourne Oil Company, Occidental Petroleum Corporation, Chevron Corporation and others. At December 31, 2015 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2015 , we also were the operator for approximately 95% of our Eagle Ford acreage and approximately two-thirds of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are proven to be the source rocks for oil and natural gas produced in the basin. Historically, production has come from the “conventional” reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +We substantially increased our acreage position in the Delaware Basin during 2015, and as a result, at December 31, 2015 , our total acreage position in Southeast New Mexico and West Texas had increased to approximately 157,100 gross ( 88,800 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,100 gross (19,400 net) acres in our Ranger prospect area in Lea County, 47,400 gross (16,900 net) acres in our Arrowhead prospect area in Eddy County, 20,700 gross (13,400 net) acres in our Rustler Breaks prospect area in Eddy County, 12,200 gross (7,500 net) acres in our Wolf and Jackson Trust prospect areas in Loving County and 42,300 gross (29,900 net) acres in our Twin Lakes prospect area in Lea County at December 31, 2015 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2015 , our acreage position in the Delaware Basin was approximately 35% held by existing production, including substantially all of the acreage acquired in the HEYCO Merger. +During the year ended December 31, 2015 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 41 gross (25.0 net) wells in the Delaware Basin, including 27 gross (23.7 net) operated wells and 14 gross (1.3 net) non-operated wells, throughout our various prospect areas. At December 31, 2015 , we had tested a number of different producing horizons at various locations across our acreage position, +6 +Table of Contents +including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, two benches of the Wolfcamp B and the Wolfcamp D. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. +In our Wolf prospect area in Loving County, Texas, we made significant progress in reducing drilling costs and times for Wolfcamp horizontal wells during 2015 . Our focus on improving drilling times and operational efficiencies cut drilling times by as much as 58% on Wolfcamp wells drilled in late 2015 in the Wolf prospect area as compared to earlier wells drilled in this area. Wolfcamp drilling times (spud to total depth) were reduced from an average of 43 days in 2014 to as low as 18 days on a well drilled in late 2015. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to our contracted drilling rigs, including 7,500-psi circulating systems, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and drilling wells in “batch” mode in the Wolf prospect area where we are in development mode. These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, reduced overall well costs in the Wolf prospect area in 2015 . Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million in late 2015, including production facilities and related infrastructure costs. At December 31, 2015, we were conducting multi-well pad operations on two separate leases in our Wolf prospect area with one rig drilling a four-well horizontal stack on the Dick Jay pad and another rig drilling a three-well horizontal stack on our Dorothy White leasehold. +We continue to improve our fracture treatment design in the Delaware Basin. In the Wolf prospect area in late October 2015, we tested the use of a fracture stimulation diverting agent in one of our Billy Burt completions in the northwest portion of the Wolf prospect—the Billy Burt 90-TTT-B33 WF #201H. The Billy Burt 90-TTT-B33 WF #201H well was a Wolfcamp A-Y test and has a completed lateral length of 6,725 feet. The diverting agent was used in an effort to improve the efficiency of each fracturing stage and to ensure as many perforation clusters were treated as possible, while simultaneously improving well costs. Breakdown pressures monitored during the fracture treatments on the Billy Burt 90-TTT-B33 WF #201H well indicated that additional perforations were opened and new hydraulic fractures were created after the diverting agent was pumped in various stages of the fracturing operation. The Billy Burt 90-TTT-B33 WF #201H well initially tested about 1,100 BOE per day (68% oil), consisting of about 750 Bbl of oil per day and 2.1 MMcf of natural gas per day. More importantly, however, early production from the well over its initial 90 days was about 27% higher than the immediate 80-acre offsetting well having a similar lateral length, but where no diverting agent was used. We continue to refine and improve our fracture treatments designs, including the use of both existing technologies and new technologies as they become available and are determined to be beneficial, in an effort to improve the overall recovery from our Delaware Basin wells. +We made significant progress with our midstream operations in 2015 , particularly in the Wolf prospect area. As noted above in “—2015 Highlights—Acquisitions and Divestitures,” we completed the sale of the Loving County System to EnLink for cash proceeds of approximately $143.4 million, excluding customary purchase price adjustments, on October 1, 2015. At closing, the Processing Plant had been online for only about a month. Although we sold the Loving County System, we retained our infield natural gas gathering system up to a central delivery point and our other midstream assets in the Wolf prospect area, including oil and water gathering systems. We also retained our interest in a commercial salt water disposal facility in Loving County, operated by a joint venture controlled by the Company. During 2015 , the joint venture entity disposed of over 5.5 million barrels of salt water, with a total savings to the Company of approximately $6.5 million in salt water disposal costs. In addition, the joint venture entity began disposing of third-party salt water on a commercial basis in the fourth quarter of 2015. +We also made significant progress delineating and testing our acreage position in the Rustler Breaks prospect area in Eddy County, New Mexico in 2015. At December 31, 2014, we had drilled and completed only one well in Rustler Breaks—the Rustler Breaks 12-24S-27E RB #224H (formerly the Rustler Breaks 12-24-27 #1H)—in a single horizon of the Wolfcamp B. By the end of 2015, we had tested four different producing horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—across our Rustler Breaks prospect area from southeast to northwest. +One of the highlights and technical achievements of 2015 was the successful drilling and completion of our first three-zone stacked lateral test on a single drilling pad in the Rustler Breaks prospect area. From this single pad location, we successfully stacked three horizontal wells targeting three different horizons including, from shallowest to deepest, the Second Bone Spring, Wolfcamp A-XY and Wolfcamp B. The Wolfcamp B well (Tiger 14-24S-28E RB #224H) tested 1,533 BOE per day (42% oil), the Wolfcamp A-XY well (Tiger 14-24S-28E RB #204H) tested 1,405 BOE per day (75% oil) and the Second Bone Spring well (Tiger 14-24S-28E RB #124H) tested 702 BOE per day (83% oil). We were encouraged not only by the early results of this important technical advance, but also by the potential further savings that we anticipate can be achieved through the repeatability of this “stacked” pay concept at other locations. We expect to drill and complete Wolfcamp wells in the Rustler Breaks prospect area for an average of $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure, and our most recent Second Bone Spring well in this area was drilled and completed for approximately $4.0 million on an existing multi-well pad, which is the least expensive Second Bone Spring well we have drilled thus far on our Delaware Basin acreage. These well costs are substantially reduced from those of initial wells drilled in this area. +7 +Table of Contents +In mid-2015, the Scott Walker State 36-22S-27E RB #204H well, a Wolfcamp A-XY completion located in the far northwestern portion of our Rustler Breaks prospect area, was completed using our Generation 2 Wolfcamp fracture treatment design with 2,000 pounds of sand per foot of completed lateral and 30 barrels of fracturing fluid per foot of completed lateral. This well tested 504 BOE per day (70% oil), consisting of 354 Bbl of oil per day and 0.9 MMcf of natural gas per day. Although this well did not test at rates as high as our Wolfcamp A-XY tests in the southeastern part of the Rustler Breaks area—the Guitar 10-24S-28E RB #202H and Tiger 14-24S-28E RB #204H wells—we were encouraged by these results as they established the prospectivity of the Wolfcamp A-XY interval across our Rustler Breaks acreage position. To our knowledge, this is the northernmost horizontal test of the Wolfcamp A-XY to date in Eddy County, New Mexico. In late 2015, we tested the Wolfcamp A-XY close to the center of our Rustler Breaks acreage position using our Generation 3 fracture treatment design with up to 3,000 pounds of sand and 40 barrels of fracturing fluid per foot of completed lateral. This well, the Dr. K 24-23S-27E RB #203H, tested 1,241 BOE per day (69% oil), consisting of 856 Bbl of oil per day and 2.3 MMcf of natural gas per day during its 24-hour initial potential test, which further establishes the prospectivity of the Wolfcamp A-XY interval across our Rustler Breaks acreage position. Also, late in 2015, we completed and placed on production two additional wells from the multi-well pad referenced above. One of these wells was the Janie Conner 13-24S-28E RB #224H, a Wolfcamp B completion, which was also stimulated with increased sand concentrations up to 3,000 pounds of sand per foot of completed lateral. During its 24-hour initial potential test, this well flowed 1,703 BOE per day (59% oil), consisting of 1,005 Bbl of oil per day and 4.2 MMcf of natural gas per day, making it the best 24-hour initial potential test of any well we have drilled thus far in the Delaware Basin. +As noted above in “—2015 Highlights—Acquisitions and Divestitures,” in the HEYCO Merger we obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross ( 18,200 net) acres strategically located between our existing acreage in our Ranger and Rustler Breaks prospect areas. Most of the acreage from the HEYCO Merger is now included primarily in our Arrowhead prospect area in Eddy County, New Mexico and our Ranger prospect area in Lea County, New Mexico. We did not drill and complete any operated wells in our Arrowhead prospect area in 2015, but we did participate in several non-operated horizontal wells in the Arrowhead prospect area subsequent to the HEYCO Merger, which results illustrate the quality and prospectivity of our acreage in this area. We participated in, or acquired through the HEYCO Merger, four wells operated by an affiliate of Concho Resources Inc. in this area, the CTA State Com #3H, #4H, #5H and #6H wells. These wells were Second Bone Spring completions and tested at an average initial production rate of 956 BOE per day (85% oil). We own an approximate 15% working interest in each of these four wells. We also participated with Mewbourne Oil Company, Inc. in its Gobbler 5 B2PM #1H well in the Arrowhead prospect area. This well, a Second Bone Spring completion, tested 2,300 BOE per day (80% oil), and we own a 6% working interest in this well. +In the Ranger prospect area in Lea County, New Mexico, our first two Second Bone Spring completions have performed above our original projections for this area. As of January 2016, the Ranger State 33-20S-35E RN #121 (formerly the Ranger 33 State Com #1H) had produced 238,000 BOE (91% oil) in its first 26 months of production. The Pickard State 20-18S-34E RN #121H (formerly the Pickard State 20-18-34 #1H), also drilled and completed in the Second Bone Spring, had produced 205,000 BOE (89% oil) in its first 18 months of production. We installed gas-lift assist on the Ranger State 33-20S-35E RN #121 well within its first two months of production, and given the early success of the gas-lift assist on that well, the Pickard State 20-18S-34E RN #121H well was also equipped with gas-lift assist within approximately 30 days of being placed on production. The use of gas-lift assist on these wells in the Ranger prospect area is one example of a transfer of technology and lessons learned from our Eagle Ford shale development program in South Texas to the Delaware Basin. Also in the Ranger prospect area, we drilled and completed the Cimarron 16-19S-34E RN #134H well in the Third Bone Spring formation. During its 24-hour initial potential test, the Cimarron 16-19S-34E RN #134H well flowed 804 BOE per day (94% oil), consisting of 754 Bbl of oil per day and 303 Mcf of natural gas per day. Subsequent to this initial potential test, an electric submersible pump (“ESP”) was run in the well to enable it to continue to clean up and produce more efficiently. This was our first use of an ESP in one of our Ranger area wells. After installing the ESP, production from the Cimarron 16-19S-34E RN #134 well increased to over 1,100 BOE per day, and in its first 8.5 months of production as of January 2016, this well produced 123,000 BOE (94% oil). We consider this to be a strong test of the Third Bone Spring, which illustrates the potential for this interval of the Bone Spring as a viable completion target throughout the Ranger prospect area. During 2015, we also participated in a non-operated Second Bone Spring well offsetting our Pickard State 20-18S-34E RN #121H well. This well, the Iggles 21 State Com #1H, tested 1,300 BOE per day (90% oil), again confirming the prospectivity of the Second Bone Spring in our Ranger prospect area. +In our Twin Lakes prospect area in northern Lea County, New Mexico, we drilled a vertical pilot hole in the fourth quarter of 2015 where we gathered a full suite of openhole well logs and both whole core and rotary sidewall core samples in preparation for drilling our first horizontal well in the Twin Lakes area, which is currently planned for late 2016. At December 31, 2015 , we were evaluating the data collected from the vertical pilot hole and evaluating several horizons in the Wolfcamp D as potential horizontal landing targets. +8 +Table of Contents +As a result of our ongoing drilling and completion operations in these prospect areas, our Delaware Basin production increased significantly in 2015 . Our average daily oil equivalent production from the Delaware Basin increased 3.6-fold from 1,790 BOE per day, including 1,314 Bbl of oil per day and 2.9 MMcf of natural gas per day, during 2014 to 6,518 BOE per day, including 4,648 Bbl of oil per day and 11.2 MMcf of natural gas per day, during 2015 . In addition, our average daily oil equivalent production from the Delaware Basin grew more than three-fold from 2,629 BOE per day in the fourth quarter of 2014 to 8,720 BOE per day in the fourth quarter of 2015 . For the year ended December 31, 2015 , 26% of our daily oil equivalent production was produced from the Delaware Basin. The Delaware Basin contributed approximately 38% of our daily oil production and approximately 15% of our daily natural gas production during 2015 , as compared to only approximately 14% of our daily oil production and approximately 7% of our daily natural gas production during 2014 . During the year ended December 31, 2014 , only approximately 11% of our daily oil equivalent production was attributable to the Delaware Basin. +At December 31, 2015 , approximately 56% of our estimated total proved oil and natural gas reserves, or 47.1 million BOE, was attributable to the Delaware Basin, including approximately 31.4 million Bbl of oil and 94.4 Bcf of natural gas, a 3.6-fold increase, as compared to 13.0 million BOE for the year ended December 31, 2014 . Our Delaware Basin proved reserves at December 31, 2015 comprised approximately 69% of our proved oil reserves and 40% of our proved natural gas reserves, as compared to approximately 33% of our proved oil reserves and 11% of our proved natural gas reserves at December 31, 2014 . The PV-10 of our proved reserves in the Delaware Basin at December 31, 2015 was $314.6 million , or approximately 58% of the PV-10 of our total proved reserves of $541.6 million . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +At December 31, 2015 , we had identified 3,543 gross ( 1,416.9 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Avalon and Delaware formations. These locations include 2,263 gross (1,284.1 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2015 do not yet include all portions of our acreage position, including the acreage associated with our Twin Lakes prospect area in Lea County, New Mexico. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2015 , these potential future drilling locations included only 118 gross (71.1 net) locations in the Delaware Basin to which we have assigned proved undeveloped reserves. +At December 31, 2015 and February 25, 2016 , we were operating three drilling rigs in the Delaware Basin—two in Loving County, Texas and one in Eddy County, New Mexico. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated approximately $315.0 million , or approximately 97% of our 2016 capital expenditure budget of $325.0 million , to our anticipated drilling, completion and midstream activities in the Delaware Basin, as well as for the acquisition of additional leasehold interests in the area. Our 2016 Delaware Basin drilling and completion program will focus on the development of the Wolf and Rustler Breaks prospect areas and the further delineation and development of our Ranger and Arrowhead prospect areas. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2015 , our properties included approximately 39,000 gross ( 29,300 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 82% of our Eagle Ford acreage was held by production at December 31, 2015 , and approximately 92% of our Eagle Ford acreage +9 +Table of Contents +was either held by production at December 31, 2015 or not burdened by lease expirations before 2017 . In the third quarter of 2015, we acquired approximately 385 gross (385 net) acres in the Eagle Ford shale in Karnes County, Texas adjacent to our Sickenius prospect that we consider to be prospective primarily for oil. We plan to continue our leasing and acquisition efforts in the Eagle Ford shale as strategic opportunities are identified. +At January 1, 2015, we were operating two rigs in the Eagle Ford shale in South Texas, but as a result of both lower oil and natural gas prices in early 2015 and the fact that, at December 31, 2014, approximately 96% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2016, we suspended our operated Eagle Ford drilling and completion operations in the second quarter of 2015. +During the year ended December 31, 2015 , we completed and began producing oil and natural gas from 18 gross (17.3 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well, all in the first few months of 2015. During the second quarter of 2015, our Eagle Ford production increased to its all-time high of 11,942 BOE per day, including 9,358 Bbl of oil per day and 15.5 MMcf of natural gas per day. We completed our planned operated Eagle Ford drilling and completion operations for 2015 in the second quarter, and as a result, our Eagle Ford production declined during the second half of 2015. Despite conducting no operated activity for more than half of 2015, our average daily oil equivalent production from the Eagle Ford shale decreased only 2% from 10,501 BOE per day, including 7,764 Bbl of oil per day and 16.4 MMcf of natural gas per day, during 2014 to 10,263 BOE per day, including 7,642 Bbl of oil per day and 15.7 MMcf of natural gas per day, during 2015 . For the year ended December 31, 2015 , 41% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2014 , approximately 65% of our daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2015 , approximately 22% of our estimated total proved oil and natural gas reserves, or 19.0 million BOE, was attributable to the Eagle Ford shale, including approximately 14.2 million Bbl of oil and 28.8 Bcf of natural gas. Our total proved reserves attributable to the Eagle Ford shale decreased approximately 15% to 19.0 million BOE for the year ended December 31, 2015 , as compared to 22.3 million BOE for the year ended December 31, 2014 , primarily as a result of declining oil and natural gas prices which resulted in certain previously classified Eagle Ford shale proved undeveloped reserves being reclassified to contingent resources at December 31, 2015. Our Eagle Ford total proved reserves at December 31, 2015 comprised approximately 31% of our proved oil reserves and 12% of our proved natural gas reserves, as compared to approximately 67% of our proved oil reserves and 14% of our proved natural gas reserves at December 31, 2014 . The PV-10 of our total proved reserves in the Eagle Ford shale was $175.1 million , or approximately 32% of the PV-10 of our total proved reserves of $541.6 million at December 31, 2015 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” +We do not plan to drill any operated Eagle Ford shale wells in 2016 , but we have allocated approximately $5.6 million , or about 2% , of our 2016 estimated capital expenditure budget of $325.0 million to the Eagle Ford shale primarily to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, if desired. +At December 31, 2015 , we had identified 260 gross ( 227.5 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate the Eagle Ford wells to be drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. While we do not plan to drill any operated wells in the Eagle Ford in 2016, approximately 92% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2017 at December 31, 2015 . As a result, these engineered drilling locations remain available to be developed by us at a future time should commodity prices improve, drilling and completion costs decline further or new technologies be developed that increase the expected recoveries. At December 31, 2015 , these 260 gross ( 227.5 net) identified drilling locations included only 27 gross (26.8 net) locations to which we have assigned proved undeveloped reserves. +We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2015 , we had not drilled any Buda wells nor had we included any Buda locations in our future drilling locations. +10 +Table of Contents +Northwest Louisiana and East Texas +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2015 , although we did participate in the drilling and completion of 22 gross (1.9 net) non-operated Haynesville shale wells that were turned to sales in 2015 . These wells included nine gross (1.6 net) Haynesville wells operated by Chesapeake on our Elm Grove acreage in southern Caddo Parish, Louisiana. In addition, Chesapeake deferred first production until early January 2016 from an additional nine gross (1.9 net) wells drilled and completed in the latter half of 2015 on our Elm Grove acreage. We do not plan to drill any operated Haynesville shale wells in 2016 , but we have budgeted capital expenditures of approximately $4.4 million for our anticipated participation in five gross (0.6 net) Haynesville shale wells that we expect to be drilled or completed and placed on production by Chesapeake on certain of our non-operated properties, including Elm Grove, in 2016 . Certain of these wells were already in progress at December 31, 2015 . +At December 31, 2015 , we held approximately 26,700 gross ( 23,800 net) acres in Northwest Louisiana and East Texas, including 20,700 gross ( 13,000 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,700 gross ( 6,800 net) acres that we consider to be in the core area of the Haynesville play. +For the year ended December 31, 2015 , approximately 33% of our average daily oil equivalent production, or 8,174 BOE per day, including 16 Bbl of oil per day and 48.9 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 64% of our daily natural gas production, but oil production from these properties comprised only about 0.1% of our daily oil production during 2015 , as compared to approximately 54% of our daily natural gas production and approximately 0.2% of our daily oil production during 2014 . During the year ended December 31, 2014 , approximately 24% of our average daily oil equivalent production, or 3,791 BOE per day, including 17 Bbl of oil per day and 22.6 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2015 , approximately 61% of our daily natural gas production, or 46.4 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.6 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2014 , approximately 47% of our daily natural gas production, or 19.7 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 7% , or 2.9 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2015 , approximately 21% of our estimated total proved reserves, or 18.1 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 0.8 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2015 , we had identified and engineered 448 gross ( 109.2 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 448 gross ( 109.2 net) locations identified for future drilling on our Haynesville acreage, 373 gross (55.3 net) locations have been identified within the 13,700 gross ( 6,800 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2015 , these potential future drilling locations included only 26 gross (9.4 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Haynesville and Middle Bossier Shales +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. +11 +Table of Contents +At December 31, 2015 , we had approximately 20,700 gross ( 13,000 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,700 gross ( 6,800 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,200 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2015 . +Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%. +Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations +Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. +All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2015 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We have identified 71 gross ( 50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2015 and do not plan to drill any of these locations in 2016 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2015 , we held an estimated 11,700 gross (9,300 net) leasehold and mineral acres by existing production in these areas. +Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale +At December 31, 2015 , we held leasehold interests in approximately 75,700 gross ( 35,700 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort on this acreage. We are the operator of this prospect. We have drilled and completed one horizontal well on this acreage, but as of December 31, 2015 , we had not established commercial natural gas production on this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2015 . We have no plans to drill on this acreage in 2016 . +12 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production data for the years ended December 31, 2015, 2014 and 2013 . +Year Ended December 31, +2015 +2014 +2013 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +4,492 +3,320 +2,133 +Natural gas (Bcf) +27.7 +15.3 +12.9 +Total oil equivalent (MBOE) (1) +9,109 +5,870 +4,285 +Average daily production (BOE/d) (1) +24,955 +16,082 +11,740 +Average Sales Prices: +Oil, with realized derivatives (per Bbl) +$ +59.13 +$ +88.94 +$ +98.67 +Oil, without realized derivatives (per Bbl) +$ +45.27 +$ +87.37 +$ +99.79 +Natural gas, with realized derivatives (per Mcf) +$ +3.24 +$ +5.06 +$ +4.47 +Natural gas, without realized derivatives (per Mcf) +$ +2.71 +$ +5.08 +$ +4.35 +Operating Expenses (per BOE): +Production taxes and marketing +$ +3.90 +$ +5.65 +$ +4.89 +Lease operating +$ +6.39 +$ +8.75 +$ +9.04 +Depletion, depreciation and amortization +$ +19.63 +$ +22.95 +$ +22.96 +General and administrative +$ +5.50 +$ +5.48 +$ +4.85 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +1,697 +2,789 +— +6 +4,492 +Natural gas (Bcf) +4.1 +5.7 +16.9 +1.0 +27.7 +Total oil equivalent (MBOE) (3) +2,379 +3,746 +2,822 +162 +9,109 +Percentage of total annual net production +26.1 +% +41.1 +% +31.0 +% +1.8 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +4,648 +7,642 +— +16 +12,306 +Natural gas (MMcf/d) +11.2 +15.7 +46.4 +2.6 +75.9 +Total oil equivalent (BOE/d) +6,518 +10,263 +7,731 +443 +24,955 +Average Sales Price (4) +Oil (per Bbl) +$ +43.54 +$ +46.33 +$ +— +$ +43.68 +$ +45.27 +Natural gas (per Mcf) +$ +3.00 +$ +3.17 +$ +2.49 +$ +2.45 +$ +2.71 +Total oil equivalent (per BOE) +$ +36.21 +$ +39.35 +$ +14.97 +$ +15.69 +$ +30.56 +Production Costs (5) +Lease operating and marketing (per BOE) +$ +9.89 +$ +9.35 +$ +4.91 +$ +19.88 +$ +8.29 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes ad valorem taxes and oil and natural gas production taxes. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2014 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +480 +2,834 +— +6 +3,320 +Natural gas (Bcf) +1.0 +6.0 +7.2 +1.1 +15.3 +Total oil equivalent (MBOE) (3) +653 +3,833 +1,201 +183 +5,870 +Percentage of total annual net production +11.1 +% +65.3 +% +20.5 +% +3.1 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +1,314 +7,764 +— +17 +9,095 +Natural gas (MMcf/d) +2.9 +16.4 +19.7 +2.9 +41.9 +Total oil equivalent (BOE/d) +1,790 +10,501 +3,290 +501 +16,082 +Average Sales Price (4) +Oil (per Bbl) +$ +80.16 +$ +88.58 +$ +— +$ +91.24 +$ +87.37 +Natural gas (per Mcf) +$ +4.75 +$ +6.72 +$ +3.87 +$ +4.30 +$ +5.08 +Total oil equivalent (per BOE) +$ +66.41 +$ +75.99 +$ +23.27 +$ +27.92 +$ +62.64 +Production Costs (5) +Lease operating and marketing (per BOE) +$ +13.11 +$ +10.45 +$ +8.13 +$ +19.09 +$ +10.53 +_________________ +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2013 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +28 +2,098 +— +6 +2,132 +Natural gas (Bcf) +— +5.4 +6.2 +1.3 +12.9 +Total oil equivalent (MBOE) (3) +31 +3,002 +1,033 +219 +4,285 +Percentage of total annual net production +0.7 +% +70.1 +% +24.1 +% +5.1 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +78 +5,748 +— +17 +5,843 +Natural gas (MMcf/d) +— +14.9 +17.0 +3.5 +35.4 +Total oil equivalent (BOE/d) +84 +8,225 +2,831 +600 +11,740 +Average Sales Price (4) +Oil (per Bbl) +$ +90.71 +$ +99.91 +$ +— +$ +102.13 +$ +99.79 +Natural gas (per Mcf) +$ +5.27 +$ +6.03 +$ +3.05 +$ +3.55 +$ +4.35 +Total oil equivalent (per BOE) +$ +86.51 +$ +80.71 +$ +18.28 +$ +23.61 +$ +62.78 +Production Costs (5) +Lease operating and marketing (per BOE) +$ +15.68 +$ +11.65 +$ +5.24 +$ +15.39 +$ +10.30 +_________________ +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 increased 55% from our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 . This increased production was primarily due to our delineation and development operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, as compared to 16,082 BOE per day for the year ended December 31, 2014 . Our average daily oil production for the year ended December 31, 2015 was 12,306 Bbl of oil per day, an increase of 35% from 9,095 Bbl of oil per day for the year ended December 31, 2014 . Our average daily natural gas production for the year ended December 31, 2015 was 75.9 MMcf of natural gas per day, an increase of 81% from 41.9 MMcf of natural gas per day for the year ended December 31, 2014 . +Our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 increased 37% from our total oil equivalent production of approximately 4.3 million BOE for the year ended December 31, 2013 . This increased production was primarily due to our drilling and completion operations in the Eagle Ford shale, as well as contributions from our initial wells in the Delaware Basin. Our average daily oil equivalent production for the year ended December 31, 2014 was 16,082 BOE per day, as compared to 11,740 BOE per day for the year ended December 31, 2013 . Our average daily oil production for the year ended December 31, 2014 was 9,095 Bbl of oil per day, an increase of 56% from 5,843 Bbl of oil per day for the year ended December 31, 2013 . Our average daily natural gas production for the year ended December 31, 2014 was 41.9 MMcf of natural gas per day, an increase of 18% from 35.4 MMcf of natural gas per day for the year ended December 31, 2013 . +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2015 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 69% in all wells that we operate at December 31, 2015, as compared to 93% at December 31, 2014, as a result of acquiring producing wells with lower working interests in the Delaware Basin as part of the HEYCO Merger in February 2015. For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +223 +84.9 +33 +11.1 +256 +96.0 +South Texas: +Eagle Ford (2) +130 +111.5 +4 +4.0 +134 +115.5 +Northwest Louisiana/East Texas: +Haynesville +— +— +198 +18.4 +198 +18.4 +Cotton Valley (3) +2 +2.0 +91 +56.4 +93 +58.4 +Area Total +2 +2.0 +289 +74.8 +291 +76.8 +Total +355 +198.4 +326 +89.9 +681 +288.3 +__________________ +(1) +Includes 175 gross (50.6 net) wells acquired in February 2015 as part of the HEYCO Merger. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2015, 2014 and 2013 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +16 +Table of Contents +At December 31, (1) +2015 +2014 +2013 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +45,644 +24,184 +16,362 +Natural Gas (Bcf) (3) +236.9 +267.1 +212.2 +Total (MBOE) (4) +85,127 +68,693 +51,729 +Estimated proved developed reserves: +Oil (MBbl) +17,129 +14,053 +8,258 +Natural Gas (Bcf) (3) +101.4 +102.8 +53.5 +Total (MBOE) (4) +34,037 +31,185 +17,168 +Percent developed +40.0 +% +45.4 +% +33.2 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +28,515 +10,131 +8,104 +Natural Gas (Bcf) (3) +135.5 +164.3 +158.7 +Total (MBOE) (4) +51,090 +37,508 +34,561 +PV-10 (5) (in millions) +$ +541.6 +$ +1,043.4 +$ +655.2 +Standardized Measure (6) (in millions) +$ +529.2 +$ +913.3 +$ +578.7 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas, and for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.67 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. +(3) +As a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves, most of which were attributable to non-operated properties in the Haynesville shale. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2015, 2014 and 2013 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015, 2014 and 2013 were, in millions, $12.4 , $130.1 and $76.5 , respectively. +(6) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +Our estimated total proved oil and natural gas reserves increase d 24% from 68.7 million BOE at December 31, 2014 to 85.1 million BOE at December 31, 2015 . We added 39.1 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2015, approximately 4.3 times our 2015 annual production of 9.1 million BOE. Our proved oil reserves grew 89% from approximately 24.2 million Bbl at December 31, 2014 to approximately 45.6 million Bbl at December 31, 2015 . This increase in proved oil reserves is primarily attributable to our drilling program in the Delaware Basin during 2015. Our proved natural gas reserves decrease d 11% from 267.1 Bcf at December 31, 2014 to 236.9 Bcf at December 31, 2015 . This decrease in proved natural gas reserves was primarily attributable to a decrease in our proved undeveloped natural gas reserves. As a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves, most of which were attributable to non-operated properties in the Haynesville shale. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +The PV-10 of our total proved oil and natural gas reserves decrease d 48% from $1.04 billion at December 31, 2014 to $541.6 million at December 31, 2015 , as a result of lower oil and natural gas prices. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2015 were $46.79 per Bbl and $2.59 per MMBtu, a decrease of 49% and 40%, respectively, as compared to average oil and natural gas prices of $91.48 per Bbl and $4.35 per MMBtu used to estimate proved reserves at December 31, 2014. Our total proved reserves at +17 +Table of Contents +December 31, 2015 were made up of approximately 54% oil and 46% natural gas, as compared to 35% oil and 65% natural gas at December 31, 2014 . +Our proved developed oil and natural gas reserves increase d 9% from 31.2 million BOE at December 31, 2014 to 34.0 million BOE at December 31, 2015 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 22% from 14.1 million Bbl at December 31, 2014 to 17.1 million Bbl at December 31, 2015 , also primarily as a result of our delineation and development operations in the Delaware Basin. Our proved developed natural gas reserves decreased 1% from 102.8 Bcf at December 31, 2014 to 101.4 Bcf at December 31, 2015 , resulting from downward revisions to certain of our proved developed natural gas reserves, primarily in the Haynesville shale, as a result of sharply lower natural gas prices in 2015, and to the 81% increase in our natural gas production to 27.7 Bcf in 2015 as compared to 15.3 Bcf in 2014. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2015 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2014 +31,185 +Extensions and discoveries +6,984 +Purchases of minerals-in-place +1,180 +Revisions of prior estimates +(2,950 +) +Production +(9,109 +) +Conversion of proved undeveloped to proved developed +6,747 +As of December 31, 2015 +34,037 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increased from 37.5 million BOE at December 31, 2014 to 51.1 million BOE at December 31, 2015 . Our proved undeveloped oil reserves increased from 10.1 million Bbl at December 31, 2014 to 28.5 million Bbl at December 31, 2015 , primarily as a result of our delineation and development operations in the Delaware Basin. Our proved undeveloped natural gas reserves decreased from 164.3 Bcf at December 31, 2014 to 135.5 Bcf at December 31, 2015 due primarily to the removal of previously classified proved undeveloped natural gas reserves from our total proved reserves, particularly in the Haynesville shale, as a result of lower natural gas prices in 2015, as noted above. +At December 31, 2015 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2015 within five years of booking these reserves. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2015 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2014 +37,508 +Extensions and discoveries +32,151 +Purchases of minerals-in-place +409 +Revisions of prior estimates +(12,231 +) +Conversion of proved undeveloped to proved developed +(6,747 +) +As of December 31, 2015 +51,090 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +The following table sets forth, since 2012, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves Converted to Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2012 +283 +0.8 +415 +$ +8,096 +2013 +2,944 +8.3 +4,334 +115,699 +2014 +3,780 +44.7 +11,223 +201,950 +2015 +2,854 +23.4 +6,747 +104,989 +Total +9,861 +77.2 +22,719 +$ +430,734 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2015 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +PV-10 (2) +Standardized Measure (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +31,395 +94.4 +47,124 +$ +314.6 +$ +307.4 +South Texas: +Eagle Ford (5) +14,221 +28.8 +19,015 +175.1 +171.1 +Northwest Louisiana/East Texas: +Haynesville +— +108.8 +18,148 +49.3 +48.2 +Cotton Valley (6) +28 +4.9 +840 +2.6 +2.5 +Area Total +28 +113.7 +18,988 +51.9 +50.7 +Other: +Wyoming, Utah, Idaho +— +— +— +— +— +Total +45,644 +236.9 +85,127 +$ +541.6 +$ +529.2 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2015 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015 were approximately $ 12.4 million . +(3) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational +19 +Table of Contents +methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 38 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2015 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +73,494 +30,814 +83,639 +57,936 +157,133 +88,750 +South Texas: +Eagle Ford +28,910 +23,431 +10,125 +5,824 +39,035 +29,255 +Northwest Louisiana/East Texas: +Haynesville +17,343 +9,644 +3,364 +3,363 +20,707 +13,007 +Cotton Valley +18,189 +16,111 +3,586 +3,074 +21,775 +19,185 +Area Total (1) +22,634 +20,315 +4,030 +3,517 +26,663 +23,831 +Other: +Wyoming, Utah, Idaho +1,600 +800 +74,074 +34,932 +75,674 +35,732 +Total +126,638 +75,360 +171,868 +102,209 +298,505 +177,568 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2015 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2019 and beyond represents an immaterial amount of our overall undeveloped acreage. +20 +Table of Contents +Acres +Acres +Acres +Expiring 2016 +Expiring 2017 +Expiring 2018 +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +34,235 +21,175 +17,188 +10,336 +18,045 +14,077 +South Texas: +Eagle Ford (2) +2,633 +2,435 +2,510 +2,484 +477 +477 +Northwest Louisiana/East Texas: +Haynesville +524 +523 +— +— +— +— +Cotton Valley +80 +80 +— +— +— +— +Area Total (3) +524 +523 +— +— +— +— +Other: +Wyoming, Utah, Idaho +— +— +21,874 +9,575 +48,859 +24,605 +Total +37,392 +24,133 +41,572 +22,395 +67,381 +39,159 +__________________ +(1) +Approximately 60% of the acreage expiring in 2016 is associated with our Twin Lakes prospect area in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes prospect area in 2016 through our 2016 drilling activities or by paying an additional lease bonus, where applicable. +(2) +We expect to extend portions of our expiring Eagle Ford acreage in 2016 by paying an additional lease bonus. +(3) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2015 , our leases are primarily fee and state leases with primary terms of three to five years. As a result of the HEYCO Merger in 2015, we also have acquired a significant number of federal leases with primary terms of 10 years; however, essentially all of the federal leases acquired in the HEYCO Merger are held by production. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2015, 2014 and 2013 . +Year Ended December 31, +2015 +2014 +2013 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +53 +26.7 +89 +39.9 +32 +20.7 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +28 +17.5 +12 +10.6 +14 +8.7 +Dry (1) +— +— +— +— +1 +0.4 +Total Wells +Productive +81 +44.2 +101 +50.5 +46 +29.4 +Dry (1) +— +— +— +— +1 +0.4 +__________________ +(1) We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013. +21 +Table of Contents +Marketing +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the year ended December 31, 2015 , we had three significant purchasers that accounted for approximately 59% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2014 and 2013 , we had three and five significant purchasers that accounted for approximately 68% and 87% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, we had an immaterial natural gas deficiency and the counterparty to this agreement waived the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” +As part of the sale of the Loving County System (See Note 5 to the consolidated financial statements in this Annual Report on Form 10-K), we entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby we committed to deliver the anticipated natural gas production from a significant portion of our Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facility. Under this agreement, if we do not meet the volume commitment for transportation and processing at the facility in a contract year, we will be required +22 +Table of Contents +to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, we can elect to have the previous year’s actual transportation and processing commitment be the new minimum commitment for each of the remaining years of the contract. As such, we have the ability to unilaterally reduce the transportation and processing commitment if our production in the Loving County area is less than our currently projected production. If we ceased operations in this area at December 31, 2015 , the total deficiency fee required to be paid would be approximately $9.6 million . In addition, if we elect to reduce the transportation and processing commitment in any year, we have the ability to elect to increase the committed volumes in any future year to the originally agreed transportation and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. We paid approximately $1.8 million in processing and transportation fees under this agreement during the year ended December 31, 2015 . We can elect to either sell the residue gas to the counterparty at the tailgate of its processing plant or have the counterparty deliver to us the residue gas in-kind to be sold to third parties downstream of the plant. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations. +Competition +The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” +23 +Table of Contents +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. +Texas, New Mexico, Louisiana, Wyoming, Idaho, Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue. +In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. +The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +24 +Table of Contents +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). +Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. +Environmental Regulation +The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. +25 +Table of Contents +We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil +26 +Table of Contents +and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Since January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. Further, in August 2015, the EPA issued proposed NSPS governing methane emissions from the oil and natural gas industry as well as proposed source determination standards for determining when oil and natural gas sources should be aggregated for CAA permitting and compliance purposes. The proposed NSPS for methane would extend the 2012 NSPS to remaining equipment and processes not currently regulated under the existing standards, including completions of hydraulically fractured oil wells, equipment leaks, pneumatic pumps and natural gas compressor station compressors. We continue to evaluate the effect these proposed rules would have on our business and operations. On January 22, 2016, the Department of the Interior proposed rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The proposed rules would, among other things, limit routine flaring of natural gas, require the payment of royalties on avoidable gas losses and require plans or programs relating to gas capture and leak detection and repair. The proposed rules are still in the period for public comment. These rules could increase our operating costs and have a material adverse effect on our business and operations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. In addition, ongoing international discussions are exploring options to succeed the Kyoto Protocol, most recently at the United Nations Conference on climate change in Paris in November-December 2015. These discussions could result in a legally binding international agreement to make certain global emissions reductions at a national level, which in turn could further drive regulation in the United States. Any future international agreements, federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, reporting of greenhouse gas emissions from onshore oil and natural gas production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2015 , we owned and operated nine underground injection wells and owned but did not operate two underground injection wells through a less-than-wholly-owned subsidiary, and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or +27 +Table of Contents +operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows. +In addition, some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. At the state level, Texas, New Mexico and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few state and local governments or regional authorities have imposed temporary moratoria on drilling permits. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing within city limits. These actions are the subject of legal challenges. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. +The EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, in June 2015, the EPA issued draft results of its study on the effects of hydraulic fracturing on drinking water resources. The EPA did not find evidence of widespread, systemic impacts on drinking water resources in the United States, although it did note a lack of data in many areas. Further, the BLM issued final rules to regulate hydraulic fracturing on federal lands in March 2015, although these rules have been temporarily stayed by the federal district court for the District of Wyoming pending litigation. The EPA has also announced an Advance Notice of Proposed Rulemaking under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, +have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +28 +Table of Contents +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report on Form 10-K for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2015 , we had 151 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary +29 +Table of Contents +at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. \ No newline at end of file diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/item13.txt b/raw/filings/0001520006/2015/0001520006-16-000245/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8ea36dfefd8d51b5da312ba21694678384ff7d76 --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. \ No newline at end of file diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/item9a.txt b/raw/filings/0001520006/2015/0001520006-16-000245/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..34c9c4c0f5e091fa1177644d342636fc2dedef76 --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/item9a.txt @@ -0,0 +1,28 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +75 +Table of Contents +As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2015 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2015 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2015 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +76 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2015 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2015 and 2014 , and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the each of the years in the two-year period ended December 31, 2015 , and our report dated February 29, 2016 expressed an unqualified opinion on those consolidated financial statements. +/s/ KPMG LLP +Dallas, Texas +February 29, 2016 +77 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/rp_note.txt b/raw/filings/0001520006/2015/0001520006-16-000245/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..66b13ed4e41a3c81cb1d3c5b4cb0877b485ad958 --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/rp_note.txt @@ -0,0 +1,545 @@ +NOTE 16 — RELATED PARTY TRANSACTIONS +In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2015 , the Company had contributed an aggregate of approximately $0.7 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. +Additionally, substantially all of the oil production from the wells acquired in the HEYCO Merger was subject to pre-existing sales contracts with an entity owned by affiliates of HEYCO Energy Group, Inc. The Company recorded revenue of $1.1 million for oil sold pursuant to such contracts for the year ended December 31, 2015 . Such contracts were terminated in the third quarter of 2015. +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Property acquisition costs +Proved +$ +16,524 +$ +2,728 +$ +176 +Unproved and unevaluated +253,923 +78,484 +64,305 +Exploration costs +122,495 +156,178 +99,104 +Development costs (1) +305,495 +372,982 +209,956 +Total costs incurred +$ +698,437 +$ +610,372 +$ +373,541 +__________________ +(1) +Includes midstream-related development costs of approximately $77.9 million for the year ended December 31, 2015. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2015, 2014 and 2013 , most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and installing production facilities. +Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $3.3 million , $4.0 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $6.9 million , $6.4 million and $3.7 million of these internal costs in 2015 , 2014 and 2013 , respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $3.9 million , $2.8 million and $1.9 million of its interest expense for the years ended December 31, 2015 , 2014 and 2013 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2015, 2014 and 2013 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per barrel and $2.59 per MMBtu, respectively. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per barrel and $4.35 per MMBtu, respectively. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.67 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2012 +10,485 +80,007 +23,819 +Revisions of prior estimates +(199 +) +78,812 +12,936 +Purchases of minerals in-place +— +170 +28 +Extensions and discoveries +8,209 +66,121 +19,231 +Production +(2,133 +) +(12,915 +) +(4,285 +) +Total at December 31, 2013 +16,362 +212,195 +51,729 +Revisions of prior estimates +(1,196 +) +164 +(1,169 +) +Purchases of minerals in-place +10 +433 +82 +Extensions and discoveries +12,328 +69,566 +23,921 +Production +(3,320 +) +(15,303 +) +(5,870 +) +Total at December 31, 2014 +24,184 +267,055 +68,693 +Revisions of prior estimates +(2,609 +) +(75,433 +) +(15,181 +) +Purchases of minerals in-place +1,102 +2,927 +1,589 +Extensions and discoveries +27,459 +70,054 +39,135 +Production +(4,492 +) +(27,702 +) +(9,109 +) +Total at December 31, 2015 +45,644 +236,901 +85,127 +Proved Developed Reserves +December 31, 2012 +4,764 +54,040 +13,771 +December 31, 2013 +8,258 +53,458 +17,168 +December 31, 2014 +14,053 +102,795 +31,185 +December 31, 2015 +17,129 +101,447 +34,037 +Proved Undeveloped Reserves +December 31, 2012 +5,721 +25,967 +10,048 +December 31, 2013 +8,104 +158,737 +34,561 +December 31, 2014 +10,131 +164,260 +37,508 +December 31, 2015 +28,515 +135,454 +51,090 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2015, 2014 and 2013 . +The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from 68,693 MBOE at December 31, 2014 . The Company’s proved oil and natural gas reserves increased by 25,543 MBOE and the Company produced 9,109 MBOE during the year ended December 31, 2015 , resulting in a net increase of 16,434 MBOE. An increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the removal of approximately 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015 , as well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves, primarily in the Haynesville shale in Northwest Louisiana, resulting from the decline in commodity prices during 2015. The Company also purchased minerals in-place with proved reserves of 1,589 MBOE in 2015 , primarily as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to 34,037 MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014 , primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2015 , the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately 60% proved undeveloped. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s proved oil and natural gas reserves increased to 68,693 MBOE at December 31, 2014 from 51,729 MBOE at December 31, 2013 . The Company’s proved oil and natural gas reserves increased by 22,834 MBOE and the Company produced 5,870 MBOE during the year ended December 31, 2014 , resulting in a net increase of 16,964 MBOE. An increase of 23,921 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, plus additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves decreased by 1,169 MBOE during the year as a result of revisions to previous estimates, primarily downward revisions of proved undeveloped oil reserves on certain of the Company’s undeveloped locations in the Eagle Ford shale play in South Texas in 2014 . The Company also purchased minerals in-place with proved reserves of 82 MBOE in 2014. The Company’s proved developed oil and natural gas reserves increased to 31,185 MBOE at December 31, 2014 from 17,168 MBOE at December 31, 2013 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale and in the Wolfcamp and Bone Spring plays in the Delaware Basin plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2014 , the Company’s proved reserves were made up of approximately 35% oil and 65% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 51,729 MBOE at December 31, 2013 from 23,819 MBOE at December 31, 2012 . The Company’s proved oil and natural gas reserves increased by 32,195 MBOE and the Company produced 4,285 MBOE during the year ended December 31, 2013 , resulting in a net increase of 27,910 MBOE. An increase of 19,231 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves increased by 12,936 MBOE during the year as a result of revisions to previous estimates, primarily upward revisions in the Company’s proved undeveloped natural gas reserves resulting from higher natural gas prices in 2013 . The Company also purchased minerals in-place with proved reserves of 28 MBOE in 2013. The Company’s proved developed oil and natural gas reserves increased to 17,168 MBOE at December 31, 2013 from 13,771 MBOE at December 31, 2012 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2013 , the Company’s proved reserves were made up of approximately 32% oil and 68% natural gas and were approximately 33% proved developed and 67% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2015 , the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $46.79 per barrel and $2.59 per MMBtu, respectively. For the period from January through December 2014 , the comparable average oil and natural gas prices were $91.48 per barrel and $4.35 per MMBtu, respectively. For the period from January through December 2013 , the comparable average oil and natural gas prices were $93.42 per barrel and $3.67 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and marketing costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Future cash inflows +$ +2,461,131 +$ +3,197,317 +$ +2,316,626 +Future production costs +(843,117 +) +(803,662 +) +(666,450 +) +Future development costs +(615,692 +) +(553,799 +) +(507,923 +) +Future income tax expense +(43,956 +) +(321,088 +) +(181,041 +) +Future net cash flows +958,366 +1,518,768 +961,212 +10% annual discount for estimated timing of cash flows +(429,185 +) +(605,449 +) +(382,544 +) +Standardized measure of discounted future net cash flows +$ +529,181 +$ +913,319 +$ +578,668 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 (in thousands). +Year Ended December 31, +2015 +2014 +2013 +Balance, beginning of period +$ +913,319 +$ +578,668 +$ +394,636 +Net change in sales and transfer prices and in production (lifting) costs related to future production +(509,901 +) +87,067 +(97,511 +) +Changes in estimated future development costs +(145,861 +) +(150,447 +) +(233,232 +) +Sales and transfers of oil and natural gas produced during the period +(184,612 +) +(283,187 +) +(209,338 +) +Purchases of reserves in place +16,321 +1,838 +176 +Net change due to extensions and discoveries +401,895 +537,472 +386,696 +Net change due to revisions in estimates of reserves quantities +(285,823 +) +(26,263 +) +260,148 +Previously estimated development costs incurred during the period +121,543 +187,459 +106,348 +Accretion of discount +82,574 +65,518 +36,184 +Other +2,029 +5,492 +(371 +) +Net change in income taxes +117,697 +(90,298 +) +(65,068 +) +Standardized measure of discounted future net cash flows +$ +529,181 +$ +913,319 +$ +578,668 +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2015, 2014 and 2013 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2015 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2015 +Oil and natural gas revenues +$ +56,212 +$ +71,815 +$ +87,848 +$ +62,465 +Realized gain on derivatives +24,948 +19,862 +13,780 +18,504 +Unrealized (loss) gain on derivatives +(13,909 +) +6,733 +(23,532 +) +(8,557 +) +Expenses (1) +290,769 +367,499 +319,095 +147,217 +Other expense +5,101 +6,230 +5,367 +1,783 +(Loss) income before income taxes +(228,619 +) +(275,319 +) +(246,366 +) +(76,588 +) +Income tax provision (benefit) +1,677 +(33,305 +) +(89,350 +) +(26,390 +) +Net loss +(230,296 +) +(242,014 +) +(157,016 +) +(50,198 +) +Net income attributable to non-controlling interest in subsidiaries +(105 +) +(45 +) +(75 +) +(36 +) +Net loss attributable to +Matador Resources Company shareholders +$ +(230,401 +) +$ +(242,059 +) +$ +(157,091 +) +$ +(50,234 +) +Loss per common share attributable to Matador Resources Company shareholders +Basic +$ +(2.72 +) +$ +(2.86 +) +$ +(1.89 +) +$ +(0.68 +) +Diluted +$ +(2.72 +) +$ +(2.86 +) +$ +(1.89 +) +$ +(0.68 +) +__________________ +(1) +Expenses for December 31, September 30, June 30 and March 31, 2015 included full-cost ceiling impairment charges of $219.4 million, $285.7 million, $229.0 million and $67.1 million, respectively. +The following table presents selected unaudited quarterly financial information for 2014 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2014 +Oil and natural gas revenues +$ +93,110 +$ +96,617 +$ +99,054 +$ +78,931 +Realized gain (loss) on derivatives +10,479 +(701 +) +(2,913 +) +(1,843 +) +Unrealized gain (loss) on derivatives +50,351 +16,293 +(5,234 +) +(3,108 +) +Expenses +78,675 +65,680 +60,840 +46,723 +Other expense +1,018 +406 +1,207 +1,358 +Income before income taxes +74,247 +46,123 +28,860 +25,899 +Income tax provision +27,701 +16,504 +10,634 +9,536 +Net income +46,546 +29,619 +18,226 +16,363 +Net loss attributable to non-controlling interest in subsidiaries +17 +— +— +— +Net income attributable to +Matador Resources Company shareholders +$ +46,563 +$ +29,619 +$ +18,226 +$ +16,363 +Earnings per common share attributable to Matador Resources Company shareholders +Basic +$ +0.63 +$ +0.40 +$ +0.27 +$ +0.25 +Diluted +$ +0.63 +$ +0.40 +$ +0.26 +$ +0.25 +F-40 \ No newline at end of file diff --git a/raw/filings/0001520006/2015/0001520006-16-000245/rpt_disclosure.txt b/raw/filings/0001520006/2015/0001520006-16-000245/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..9aa8b65e318ecfc8b860ad8484b9d2dd0cd9d463 --- /dev/null +++ b/raw/filings/0001520006/2015/0001520006-16-000245/rpt_disclosure.txt @@ -0,0 +1,109 @@ +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2016 there was not, nor was there proposed as of December 31, 2016, any transaction or series of +similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the +immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive +Compensation — Compensation Discussion and Analysis” above. +HEYCO Joint Ventures +In June 2015, the Company entered into two joint ventures (the “Joint Ventures”) to develop certain leasehold interests held by +certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of Harvey E. Yates Company. The HEYCO Affiliates are owned by George M. Yates, who was appointed to the Board on April 28, 2015 in +accordance with the terms of the HEYCO Merger, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held +by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of +December 31, 2016, the Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s contributions are being used to fund capital expenditures associated with the interests owned by the Joint +Ventures as well as to fund acquisitions by the Joint Ventures of other non-operated acreage opportunities. +The Audit Committee reviewed the terms of the Joint Ventures for potential conflicts of interest under the Company’s related party transaction policy, effective October 12, 2011 (the +“Related Party Transaction Policy”), and, after being fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Joint Ventures, determined that the Joint Ventures were fair to the +Company and recommended the Joint Ventures to the full Board for approval and ratification. The Board subsequently approved and ratified the Joint Ventures. +In addition, in light of Mr. Yates’ ongoing services to HEYCO Energy Group, Inc., the Board, in accordance with Texas corporate law, adopted resolutions which renounce and provide for a waiver +of certain corporate opportunities with respect to Mr. Yates. As a result, Mr. Yates will have no fiduciary duty to present certain corporate opportunities related to Mr. Yates’ existing oil and gas holdings and/or in areas where +Matador does not currently operate. +Working Interest Acquisition +A sibling of Mr. Yates is affiliated with and controls Jalapeno Corporation (“Jalapeno”). In an arms-length transaction +completed in 2016, the Company acquired Jalapeno’s working interest in certain oil and natural gas properties operated by the Company (the “Working Interest Acquisition”). The Company paid Jalapeno approximately $3.6 million for +the Working Interest Acquisition. +The Audit Committee reviewed the terms of the Working Interest Acquisition for potential +conflicts of interest under the Related Party Transaction Policy and, after being fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Working Interest Acquisition, determined that the +Working Interest Acquisition was fair to the Company and recommended the Working Interest Acquisition to the full Board for approval and ratification. The Board subsequently approved and ratified the Working Interest Acquisition. +Term Assignment +A +sibling of Mr. Yates is affiliated with and controls Yates Energy Corporation (“Yates Energy”). In an arms-length transaction completed in 2016, the Company acquired a term assignment of Yates Energy’s working +60 +Table of Contents +interest in certain oil and natural gas properties operated by the Company (the “Term Assignment”). The Company paid Yates Energy approximately $170,000 for the Term Assignment. +The Audit Committee reviewed the terms of the Term Assignment for potential conflicts of interest under the Related Party +Transaction Policy and, after being fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Term Assignment, determined that the Term Assignment was fair to the Company and recommended the Term +Assignment to the full Board for approval and ratification. The Board subsequently approved and ratified the Term Assignment. +Working +Interest and Overriding Royalty Interest Owners +Certain HEYCO Affiliates or entities controlled by members of +Mr. Yates’ family (collectively, the “Yates Entities”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As +working interest owners, the Yates Entities are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the +Yates Entities are entitled to receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2016, revenues, net of costs, received by the Yates Entities in their capacities as +working interest owners or overriding royalty interest owners were approximately $883,000 (the “Yates Net Revenue Payments”). +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2016, our joint interest billings to the Yates +Entities attributable to their share of costs were approximately $1.1 million (the “Yates Billings”). This represents less than 1% of our total joint interest billings during 2016. As a result of this ownership by the Yates Entities, +from time to time, we will be in a net receivable or net payable position with the Yates Entities. We do not consider any net receivables from these parties to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Yates Entities for potential +conflicts of interest under the Related Party Transaction Policy, and, after being fully informed as to Mr. Yates’ relationship and interest in such transactions and all other material facts related to the Yates Net Revenue Payments and +Yates Billings, determined that such transactions and the Yates Net Revenue Payments and Yates Billings were fair to the Company and recommended such transactions and the Yates Net Revenue Payments and Yates Billings to the full Board for approval +and ratification. The Board subsequently approved and ratified the transactions and the Yates Net Revenue Payments and Yates Billings. +Certain Employment Relationships +Billy E. Goodwin, Senior Vice President — Operations, was appointed as an executive officer of the Company in connection with his February 2016 promotion to his present role. Two of +Mr. Goodwin’s adult children are employees of the Company and each earned in 2016, and are expected to be compensated in 2017, between $120,000 and $500,000. One of Mr. Goodwin’s children has a bachelor’s degree in petroleum +engineering from the University of Tulsa and over seven years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other child has a bachelor’s +degree in energy management from the University of Tulsa and a bachelor’s degree in general business and management from Oklahoma State University. He also has over seven years of industry experience, including as a drilling fluids engineer for +a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangements for potential conflicts of interest under the Company’s +Related Party Transaction Policy and, after being fully informed as to the employment arrangements and historical and anticipated compensation of Mr. Goodwin’s adult children, and all other material facts related to the relationship, +determined that the employment arrangements were fair to the Company and recommended the employment arrangements to +61 +Table of Contents +the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s +sister-in-law is an employee of the Company and earned in 2016, and is expected to be compensated in 2017 between $120,000 and $200,000. Mr. Baribault’s +sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist University Legal Assistants Program. She has over 35 years of experience as a legal assistant. The Audit +Committee reviewed the terms of the employment arrangements for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being fully informed as to the employment arrangements and historical and +anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement +was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of Joseph Wm. Foran, Chairman and CEO, is an employee of the Company and is expected to be compensated in 2017 between +$120,000 and $200,000. Mr. Foran’s child has a bachelor’s degree in human resources development and a master’s degree in human resources management, both from Texas A&M University. She has more than six years of industry +experience, including with another publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Party Transaction Policy +and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Foran’s adult child, and all other material facts related to the relationship, determined that the employment arrangement +was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +Procedures for Approval of Related Party Transactions +Pursuant to the Related Party Transaction Policy, a “Related Party Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any +indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, involving a Related Party (as defined below) and in which we are a participant, other than: +• +a transaction involving compensation of directors; +• +a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, change in control provision or +agreement or a special supplemental benefit for an executive officer; +• +a transaction available to all employees generally or to all salaried employees generally; +• +a transaction with a Related Party involving less than $120,000; +• +a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that +class receive the same benefit on a pro rata basis; or +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of +services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. +“Related Party” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or nominees for directors; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, +son-in-law, daughter-in-law, +62 +Table of Contents +brother-in-law or sister-in-law of +a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• +any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general +partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Party Transaction Policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or disapproval of the Related Party +Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all material facts of the Related Party +Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be disclosed in our filings with the SEC +and/or our website in accordance with applicable laws, rules and regulations. +63 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/filing.txt b/raw/filings/0001520006/2016/0001520006-17-000074/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..7a2d2b73bda55482e17ba0957d18aa2e40941208 --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/filing.txt @@ -0,0 +1,6976 @@ +10-K +1 +mtdr10-k12312016.htm +10-K +Document +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2016 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission file number 001-34574 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas +27-4662601 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 +Dallas, Texas 75240 +75240 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: (972) 371-5200 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ý No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +ý +Accelerated filer +¨ +Non-accelerated filer +¨ +(Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ¨ No ý +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,625,286,901 . +As of February 24, 2017 , there were 100,034,559 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2017 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2016 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +BUSINESS +2 +I TEM 1A. +RISK FACTORS +28 +I TEM 1B. +UNRESOLVED STAFF COMMENTS +49 +I TEM 2. +PROPERTIES +49 +I TEM 3. +LEGAL PROCEEDINGS +49 +I TEM 4. +MINE SAFETY DISCLOSURES +50 +PART II +I TEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +51 +I TEM 6. +SELECTED FINANCIAL DATA +54 +I TEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +56 +I TEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +76 +I TEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +77 +I TEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +77 +I TEM 9A. +CONTROLS AND PROCEDURES +77 +I TEM 9B. +OTHER INFORMATION +80 +PART III +I TEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +80 +I TEM 11. +EXECUTIVE COMPENSATION +80 +I TEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +80 +I TEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +80 +I TEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +80 +PART IV +I TEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +81 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, the sufficiency of our cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission, or the SEC, all of which are difficult to predict. Forward-looking statements may include statements about: +• +our business strategy; +• +our reserves; +• +our technology; +• +our cash flows and liquidity; +• +our financial strategy, budget, projections and operating results; +• +our oil and natural gas realized prices; +• +the timing and amount of future production of oil and natural gas; +• +the availability of drilling and production equipment; +• +the availability of oil field labor; +• +the amount, nature and timing of capital expenditures, including future exploration and development costs; +• +the availability and terms of capital; +• +our drilling of wells; +• +our ability to negotiate and consummate acquisition and divestiture opportunities; +• +government regulation and taxation of the oil and natural gas industry; +• +our marketing of oil and natural gas; +• +our exploitation projects or property acquisitions; +• +the integration of acquisitions with our business; +• +our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the expansion of our Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; +• +our costs of exploiting and developing our properties and conducting other operations; +• +general economic conditions; +• +competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• +the effectiveness of our risk management and hedging activities; +• +environmental liabilities; +• +counterparty credit risk; +• +developments in oil-producing and natural gas-producing countries; +• +our future operating results; +• +estimated future reserves and the present value thereof; and +• +our plans, objectives, expectations and intentions contained in this Annual Report that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +1 +Table of Contents +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations primarily, as of February 17, 2017, through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment in 2016 , the successful execution of our business strategies led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also significantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important financing transactions in 2016 , including two equity offerings, an issuance of senior unsecured notes and an increase in the borrowing base under our Credit Agreement (as defined below). These transactions, as well as the formation of the Joint Venture in February 2017, increased our operational flexibility and further strengthened our balance sheet. +2 +Table of Contents +2016 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2016 , we achieved record oil, natural gas and average daily oil equivalent production. In 2016 , we produced 5.1 million Bbl of oil, an increase of 13% , as compared to 4.5 million Bbl of oil produced in 2015 . We also produced 30.5 Bcf of natural gas, an increase of 10% from 27.7 Bcf of natural gas produced in 2015 . Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, an increase of 12% , as compared to 24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, for the year ended December 31, 2015 . The increase in oil and natural gas production was primarily a result of our ongoing delineation and development operations in the Delaware Basin throughout 2016 , which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2016 , as compared to 49% for the year ended December 31, 2015 . +Increased Oil and Oil Equivalent Reserves +At December 31, 2016 , our estimated total proved oil and natural gas reserves were 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, an increase of 24% from December 31, 2015 . The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 9% and 7% to $575.0 million and $581.5 million , respectively, at December 31, 2016 , from $529.2 million and $541.6 million , respectively, at December 31, 2015 , primarily as a result of our ongoing delineation and development operations in the Delaware Basin. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 25% to 57.0 million Bbl at December 31, 2016 from 45.6 million Bbl at December 31, 2015 . Our proved natural gas reserves increased 24% to 292.6 Bcf at December 31, 2016 from 236.9 Bcf at December 31, 2015 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development operations in the Delaware Basin during 2016 . +At December 31, 2016 , proved developed reserves included 22.6 million Bbl of oil and 126.8 Bcf of natural gas, and proved undeveloped reserves included 34.4 million Bbl of oil and 165.9 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 41% and 54% , respectively, of our total proved oil and natural gas reserves at December 31, 2016 . Proved developed reserves and proved oil reserves comprised 40% and 54% , respectively, of our total proved oil and natural gas reserves at December 31, 2015 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past three years, as we continue to apply what we learned from our Eagle Ford shale and Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2017. +We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin in 2016 , including 40 gross (35.6 net) operated and 15 gross (1.4 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2016 . As a result, at December 31, 2016 , our total acreage position in the Delaware Basin had increased to approximately 163,700 gross ( 94,300 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been very pleased with the initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our six main asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Ranger and Twin Lakes asset areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 145% (2.5-fold) to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 , as compared to 6,518 BOE per day ( 26% of total oil equivalent production), including 4,648 Bbl of oil per day ( 38% of total oil production) and 11.2 MMcf of natural gas per day ( 15% of total natural gas production), in 2015 . We expect our Delaware Basin production to increase throughout 2017 as we continue the delineation and development of these asset areas. +3 +Table of Contents +Operational highlights in the Delaware Basin (as further described below in “—Principal Areas of Interest — Exploration and Production Segment—Southeast New Mexico and West Texas — Delaware Basin” and “—Midstream Segment”) in 2016 included: +• +our continued improvement in operational efficiencies throughout the Delaware Basin, particularly in our Rustler Breaks and Wolf asset areas, as we achieved improvements in both drilling times and well costs; +• +in our Rustler Breaks asset area, the continued delineation and development of previously tested horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—and the successful testing of a new, deeper bench of the Wolfcamp B interval, which is sometimes referred to as the Blair Shale; +• +in our Wolf asset area, continued development of the Wolfcamp A-XY interval as well as the significant improvement in well results in the Second Bone Spring, as compared to our initial tests in that interval; +• +in our Ranger asset area, the initial results from three wells completed in the Third Bone Spring formation on our Mallon leasehold, which tested at the highest 24-hour initial potential flow rates of any wells we have drilled to date in the Delaware Basin and which illustrate the potential of our northern Delaware Basin acreage position; +• +a positive test of the Strawn formation in our Twin Lakes asset area from the Olivine State 5-16S-37E TL #1, a vertical well; and +• +the significant progress made with our midstream operations including the start-up of our Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) and associated natural gas gathering system in our Rustler Breaks asset area, our initial salt water disposal well and facility and associated water gathering lines in our Rustler Breaks asset area and two additional salt water disposal wells and facilities in our Wolf asset area. +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or in Northwest Louisiana and East Texas during 2016 , although we did participate in the drilling and completion of 2 gross (less than 0.1 net) non-operated Eagle Ford shale wells and 15 gross (2.1 net) non-operated Haynesville shale wells that began producing in 2016 . +Financing Arrangements +On March 11, 2016, we completed a public offering of 7,500,000 shares of our common stock. After deducting offering costs totaling approximately $0.8 million , we received net proceeds of approximately $141.5 million . In late October 2016 , the lenders party to our third amended and restated credit agreement (the “Credit Agreement”), under which we had no borrowings outstanding at December 31, 2016 , increased our borrowing base from $300.0 million to $400.0 million . On December 9, 2016, we issued $175.0 million of our 6.875% senior unsecured notes due 2023 (the “Additional Notes”) in a private placement. We received net proceeds from the issuance of Additional Notes of $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. Also on December 9, 2016, we completed a public offering of 6,000,000 shares of our common stock. After deducting offering costs totaling approximately $0.4 million , we received net proceeds of approximately $145.8 million . See Notes 6 and 10 to the consolidated financial statements in this Annual Report for more details on each of the above items. +2017 Recent Developments +Between January 1, 2017 and February 22, 2017 , we acquired approximately 13,900 gross (8,200 net) leasehold and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around our existing acreage in the Delaware Basin. Some of this acreage, and a portion of the production, included properties identified at the time of our December 2016 equity and notes offerings. These transactions were pending at the time of those offerings and closed subsequent to December 31, 2016, bringing our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres, almost all of which was located in the Delaware Basin. We have incurred capital expenditures of approximately $111 million since January 1, 2017 to acquire leasehold and mineral interests and the related production. +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the next five years. We continue to operate the Delaware Midstream Assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will continue to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +4 +Table of Contents +Principal Areas of Interest — Exploration and Production Segment +Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana and East Texas. During 2016 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our asset areas by exploring for more conventional targets as well, although at December 31, 2016 , essentially all of our efforts were focused on unconventional plays. +At December 31, 2016 , our principal areas of interest consisted of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2016 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +163,703 +94,312 +312 +135.1 +4,162 +1,660.2 +79,388 +35.5 +15,941 +South Texas: +Eagle Ford (5) +30,669 +27,777 +136 +115.1 +249 +214.2 +13,298 +55.0 +4,952 +Northwest Louisiana/East Texas: +Haynesville +20,105 +12,452 +204 +19.8 +431 +103.0 +12,414 +61.1 +6,517 +Cotton Valley (6) +21,614 +19,071 +81 +54.2 +71 +50.1 +652 +100.0 +403 +Area Total (7) +26,062 +23,278 +285 +74.0 +502 +153.1 +13,066 +63.0 +6,920 +Total (8) +220,434 +145,367 +733 +324.2 +4,913 +2,027.5 +105,752 +41.4 +27,813 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2016 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2016 , these engineered drilling locations included only 163 gross (90.3 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Delaware and Strawn formations in the Delaware Basin, 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 12 gross (4.0 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2016 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +(8) +During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho. +We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, Cimarex Energy Company, BHP Billiton, Mewbourne Oil Company, Occidental Petroleum Corporation, Chevron Corporation and others. At December 31, 2016 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2016 , we also were the operator for approximately 93% of our Eagle Ford acreage and +5 +Table of Contents +approximately 65% of our Haynesville acreage, including approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +As noted above in “—2016 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2016 , and as a result, at December 31, 2016 , our total acreage position in Southeast New Mexico and West Texas was approximately 163,700 gross ( 94,300 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,700 gross (20,400 net) acres in our Ranger asset area in Lea County, 48,000 gross (17,000 net) acres in our Arrowhead asset area in Eddy County, 25,100 gross (16,500 net) acres in our Rustler Breaks asset area in Eddy County, 13,500 gross (8,400 net) acres in our Wolf and Jackson Trust asset areas in Loving County and 42,900 gross (30,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2016 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2016 , our acreage position in the Delaware Basin was approximately 36% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical Strawn well, our acreage position in the Delaware Basin was approximately 47% held by existing production at December 31, 2016. +During the year ended December 31, 2016 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin, including 40 gross (35.6 net) operated wells and 15 gross (1.4 net) non-operated wells, throughout our various asset areas. At December 31, 2016 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2016 . Our average daily oil equivalent production from the Delaware Basin increased approximately 145% (2.5-fold) to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 , as compared to 6,518 BOE per day ( 26% of total oil equivalent production), including 4,648 Bbl of oil per day ( 38% of total oil production) and 11.2 +6 +Table of Contents +MMcf of natural gas per day ( 15% of total natural gas production), in 2015 . In addition, our average daily oil equivalent production from the Delaware Basin also grew approximately 138% (2.4-fold) from 8,720 BOE per day in the fourth quarter of 2015 to 20,670 BOE per day in the fourth quarter of 2016 . +At December 31, 2016 , approximately 75% of our estimated total proved oil and natural gas reserves, or 79.4 million BOE, was attributable to the Delaware Basin, including approximately 46.9 million Bbl of oil and 195.1 Bcf of natural gas, a 68% increase, as compared to 47.1 million BOE for the year ended December 31, 2015 . Our Delaware Basin proved reserves at December 31, 2016 comprised approximately 82% of our proved oil reserves and 67% of our proved natural gas reserves, as compared to approximately 69% of our proved oil reserves and 40% of our proved natural gas reserves at December 31, 2015 . +At December 31, 2016 , we had identified 4,162 gross ( 1,660.2 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Avalon and Delaware formations and the deeper Strawn formation. These locations include 2,546 gross (1,478.1 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2016 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our upcoming horizontal test of the Wolfcamp D in 2017). Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2016 , these potential future drilling locations included only 163 gross (90.3 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Delaware and Strawn formations, to which we have assigned proved undeveloped reserves. +At December 31, 2016 and February 22, 2017 , we were operating four drilling rigs in the Delaware Basin—two in the Rustler Breaks asset area, one in the Wolf/Jackson Trust asset areas and one in the Ranger/Arrowhead and Twin Lakes asset areas. We intend to operate four rigs in these asset areas throughout the remainder of 2017, and we expect to add a fifth drilling rig in the Delaware Basin beginning early in the second quarter of 2017. Thereafter, we expect to operate this fifth drilling rig in the Rustler Breaks asset area throughout the remainder of 2017. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated substantially all of our 2017 estimated capital expenditure budget to our drilling and completion program and midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. +Rustler Breaks Asset Area +We made significant progress delineating, developing and testing our acreage position in the Rustler Breaks asset area in 2016. The ten Wolfcamp A-XY wells and two Wolfcamp B (Middle) wells completed and placed on production in the Rustler Breaks asset area in 2016 were consistent with or better than the best Wolfcamp A-XY wells and Wolfcamp B (Middle) wells drilled by us in this asset area to date. The Paul 25-24S-28E RB #221H well tested at the highest 24-hour initial potential flow rate of any Wolfcamp A-XY well we have drilled at Rustler Breaks—1,701 BOE per day (74% oil)—and early performance from this well indicates that it may be the best Wolfcamp A-XY well drilled to date at Rustler Breaks. During 2016, we tested our first five wells drilled in the deepest bench of the Wolfcamp B (Blair) at Rustler Breaks. This is the third bench of the Wolfcamp B we have successfully tested at Rustler Breaks. These three target benches of the Wolfcamp B occur starting approximately 300 feet into the 1,000-foot thick Wolfcamp B interval at Rustler Breaks and are each about 200 to 250 feet apart vertically. +The 24-hour initial potential flow rates from the five Wolfcamp B (Blair) wells we completed and placed on production in 2016—the Dr. Scrivner Federal 01-24S-28E RB #228H, the Jimmy Kone 05-24S-28E RB #228H, the Janie Conner 13-24S-28E RB #221H, the Anne Com 15-24S-28E RB #221H (Anne Com #221H) and the Tiger 14-24S-28E RB #227H—were the five highest 24-hour test results we have reported in the Delaware Basin to date (with the exception of the three Mallon wells discussed below) at 2,570 BOE per day, 2,438 BOE per day, 2,384 BOE per day, 2,364 BOE per day and 1,812 BOE per day, respectively, at about 35% oil. These 24-hour initial potential test results compare favorably to those from other wells completed in the Wolfcamp B (Middle), the Tiger 14-24S-28E RB #224H and Janie Conner 13-24S-28E RB #224H wells, which had 24-hour initial potential rates of 1,533 BOE per day (43% oil) and 1,703 BOE per day (59% oil), respectively. The initial oil volumes from these lower Wolfcamp B (Blair) completions were reasonably comparable to or better than those in the Wolfcamp B (Middle), while the initial natural gas volumes were higher. In some instances, the oil rates tested on the lower Wolfcamp B (Blair) wells were close to those tested on the Wolfcamp A-XY wells. +7 +Table of Contents +In the Rustler Breaks asset area in 2016 , we reduced our average drilling time from spud to total depth in the Wolfcamp A-XY by approximately 31% and 16%, as compared to 2014 and 2015, respectively, and in the Wolfcamp B by approximately 50% and 35%, respectively. Our fastest-drilled Wolfcamp A-XY well, the B. Banker 33-23S-28E #226H well, was drilled in 12.5 days from spud to a total depth of 14,350 feet, a decrease of almost 50% from the average drilling time in late 2014, and our fastest-drilled Wolfcamp B well, the Anne Com #221H, was drilled in 17.4 days from spud to a total depth of 15,364 feet, a decrease of 58% from the average drilling time in 2014. These drilling times of 12.5 and 17.4 days were faster than our 2016 drilling objectives of 14 days for the Wolfcamp A-XY and 18 days for the Wolfcamp B, respectively, from spud to total depth. We delivered faster drilling times as a result of our increased knowledge of the geology and our experience with drilling in the Rustler Breaks asset area, as well as improvements in drilling the curve between the vertical and horizontal portions of these wells and continued applications of improved drill bit and bottomhole assembly technologies. +Due in part to these improvements in drilling times, continued innovation by our technical staff and lower oilfield services costs, the costs associated with recent Wolfcamp A-XY and Wolfcamp B wells at Rustler Breaks continued to decline throughout 2016. We were able to drill, complete and equip several wells in the Wolfcamp A-XY for just under $5 million each and in the Wolfcamp B for approximately $5.7 million each in mid-to-late 2016. +All of the Wolfcamp A-XY wells completed and placed on production in the Rustler Breaks asset area in 2016 were stimulated using our Generation 3 Wolfcamp stimulation treatment design, consisting of approximately 40 Bbl of fracturing fluid and 3,000 pounds of primarily 30/50 white sand per completed lateral foot. Similarly, we pumped this Generation 3 Wolfcamp stimulation treatment design in our Wolfcamp B (Blair) completions in the third and fourth quarters of 2016. Prior to this, most of our Wolfcamp A and B completions in the Rustler Breaks asset area used approximately 30 to 40 Bbl of fracturing fluid and 2,000 pounds of primarily 30/50 white sand per completed lateral foot. We also continued to pump diverting agents in most of our stimulation treatments in the Rustler Breaks asset area during the third and fourth quarters of 2016. +Wolf and Jackson Trust Asset Areas +Operational efficiencies continued to improve in the Wolf asset area as well. In 2016 , we reduced our average drilling time from spud to total depth in the Wolfcamp A-X and A-Y by approximately 52% and 10% as compared to 2014 and 2015, respectively, and in the Second Bone Spring by approximately 42% as compared to our first well drilled in the Second Bone Spring in 2015. Our fastest-drilled Wolfcamp A well, the Dorothy White 82-TTT-B33 #203H well, was drilled in 17.3 days from spud to a total depth of 15,550 feet, a decrease of 61% from the 2014 average drilling time and faster than our 2016 Wolfcamp A drilling objective of 18 days from spud to total depth in the Wolf asset area. The Barnett 90-TTT-B01 WF #124H (Barnett #124H) well, a Second Bone Spring test, was drilled in approximately 11.5 days (11.2 days normalized to a 5,000-foot lateral length) from spud to total depth, with drilling times being faster than our 2016 year-end drilling target of 13 days for Second Bone Spring wells. In the Barnett #124H and subsequent Second Bone Spring wells drilled in 2016, our drilling engineers were also able to eliminate a second intermediate casing string typically used when drilling the Second Bone Spring in this area. Not only did eliminating this casing string save approximately $650,000 in well costs on each Second Bone Spring well drilled in 2016, but it also provided for larger casing to be set through the lateral, thereby reducing hydraulic horsepower costs during fracturing operations and enhancing the number of artificial lift options available in the future. Total costs to drill, complete and equip Second Bone Spring wells in the Wolf asset area were just over $4 million in mid-to-late 2016. +Well costs associated with recent Wolfcamp A-X and A-Y wells drilled and completed in the Wolf asset area also continued to decline. Costs to drill, complete and equip Wolfcamp A wells ranged between $5 and $6 million, with a number of these wells at or below $5.5 million in mid-to-late 2016. As in the Rustler Breaks asset area, we attribute these cost savings to the innovation and use of new technologies by our drilling, completions and production teams, as well as lower oilfield services costs. +Our Second Bone Spring completions in 2016 represented significant improvements over our initial Second Bone Spring well drilled in the Wolf asset area in 2015. We attribute this improvement in well performance to the increased stimulation treatments pumped in 2016. The 2016 wells were completed using approximately 40 Bbl of fracturing fluid and 2,000 pounds of primarily 20/40 sand per completed lateral foot, compared to our initial Second Bone Spring completion in the Wolf asset area, which used only 20 Bbl of fracturing fluid and about 1,300 pounds of primarily 30/50 sand per completed lateral foot. In particular, we were pleased with the test results observed from the Johnson 44-02S-B53 WF #121H well, which had the highest test rate achieved from any Second Bone Spring well we have drilled to date of 1,167 BOE per day (58% oil). +We did not complete and place on production any new wells in our Jackson Trust asset area in 2016, although we do have several wells planned in our Jackson Trust asset area for 2017. +8 +Table of Contents +Ranger and Arrowhead Asset Areas +In the Ranger asset area in Lea County, New Mexico, we completed and placed on production the Mallon 27 Federal Com #1H, #2H and #3H wells, each of which are 7,300-foot laterals drilled and completed in the Third Bone Spring sand. These wells were the first operated wells we have drilled on the acreage acquired in our 2015 merger with Harvey E. Yates Company (“HEYCO” and, such merger, the “HEYCO Merger”). In aggregate, these three wells flowed 7,856 BOE per day (91% oil) in their 24-hour initial potential tests. Each well was completed with a 29-stage fracture treatment, including approximately 40 Bbl of fluid and 3,000 pounds of primarily 20/40 white sand per completed lateral foot. At December 31, 2016, these were the largest fracture treatments we have pumped in a Bone Spring completion. The Mallon wells were among the best wells we have drilled to date in the Delaware Basin, and these wells illustrate the potential of our northern Delaware Basin acreage position. +We did not conduct any operated drilling and completion activities in our Arrowhead asset area during 2016 , although we did participate in one new, non-operated well on our Arrowhead acreage during the first quarter of 2016. This well, the Yates Petroleum Corporation Baroque “BTQ” Federal Com #1H well, tested at flow rates averaging approximately 1,300 BOE per day (including approximately 1,100 Bbl of oil per day and 1.2 MMcf of natural gas per day) beginning in late March 2016. This well is located in the eastern portion of our Arrowhead asset area in Eddy County, New Mexico. We own a 9.5% working interest in this well, which provides yet another indication of the prospectivity of our northern Delaware Basin acreage. +Twin Lakes Asset Area +In our Twin Lakes asset area in northern Lea County, New Mexico, we drilled an initial data collection well, the Olivine State 5-16S-37E TL #1 (Olivine State #1), during the fourth quarter of 2015. This was a vertical pilot hole drilled for the purpose of collecting whole core and a detailed suite of geophysical logs to assist us in determining the landing target for our initial horizontal test of the Wolfcamp D interval at Twin Lakes. We collected about 400 feet of whole core throughout much of the Wolfcamp D interval, and our geoscience staff, along with third-party vendors, have conducted detailed description and analysis of the core data and well logs. The Olivine State #1 was drilled through the Wolfcamp D and into and through the Strawn formation below. The Strawn interval at about 11,500 feet is a complex carbonate formation that has previously produced significant quantities of oil and natural gas in the Twin Lakes area. Upon drilling through the Strawn interval, our geoscience staff analyzed the well logs taken across the interval and determined that there was the potential for a Strawn test. As a result, the Olivine State #1 was perforated and completed in the Strawn interval with a small acid treatment during the first quarter of 2016. This well flowed 691 BOE per day (84% oil) during a 24-hour initial potential test, consisting of 579 Bbl of oil per day and 0.7 MMcf of natural gas per day, at a flowing surface pressure of 350 psi on a 32/64 inch choke. Given the positive results from this Strawn test, we elected to produce the Olivine State #1 rather than plug back, kick off and drill a horizontal Wolfcamp D test from this vertical wellbore as originally anticipated. We expect to drill a new horizontal well to test the Wolfcamp D interval beginning late in the first quarter of 2017. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2016 , our properties included approximately 30,700 gross ( 27,800 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. Approximately 85% of our Eagle Ford acreage was held by production at December 31, 2016 , and approximately 95% of our Eagle Ford acreage was either held by production at December 31, 2016 or not burdened by lease expirations before 2018 . +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2016 , although we did participate in the drilling and completion of two gross (less than 0.1 net) non-operated Eagle Ford shale wells that were turned to sales in 2016 . In fact, as of December 31, 2016, we had not drilled any operated wells in the Eagle Ford shale since early 2015, when we completed and placed on production 17 gross (17.0 net) operated Eagle Ford shale wells in the first four months of 2015. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 52% to 4,952 BOE per day, including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016 , as compared to 10,263 BOE per day, including 7,642 Bbl of oil per day and 15.7 MMcf of natural gas per day, during 2015 . For the year ended December 31, 2016 , 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2015 , approximately 41% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +9 +Table of Contents +At December 31, 2016 , approximately 13% of our estimated total proved oil and natural gas reserves, or 13.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.1 million Bbl of oil and 19.3 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 18% of our proved oil reserves and 7% of our proved natural gas reserves at December 31, 2016 , as compared to approximately 31% of our proved oil reserves and 12% of our proved natural gas reserves at December 31, 2015 . +At December 31, 2016 , we had identified 249 gross ( 214.2 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. Approximately 95% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2018 at December 31, 2016 . At December 31, 2016 , these 249 gross ( 214.2 net) identified drilling locations included only 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and Edwards formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2016 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations. +Northwest Louisiana and East Texas +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2016 , although we did participate in the drilling and completion of 15 gross (2.1 net) non-operated Haynesville shale wells that were turned to sales in 2016 . These wells included nine gross (1.9 net) Haynesville wells operated by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove acreage in southern Caddo Parish, Louisiana. These nine wells came on production at an average of 13.5 MMcf per day and were drilled and completed for an average of under $7 million. We do not plan to drill any operated Haynesville shale wells in 2017 . +At December 31, 2016 , we held approximately 26,100 gross ( 23,300 net) acres in Northwest Louisiana and East Texas, including 20,100 gross ( 12,500 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the 13,200 gross ( 6,400 net) acres that we consider to be in the core area of the Haynesville play. +For the year ended December 31, 2016 , approximately 25% of our average daily oil equivalent production, or 6,920 BOE per day, including 12 Bbl of oil per day and 41.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 50% of our daily natural gas production, but oil production from these properties comprised only about 0.1% of our daily oil production during 2016 , as compared to approximately 64% of our daily natural gas production and approximately 0.1% of our daily oil production during 2015 . During the year ended December 31, 2015 , approximately 33% of our average daily oil equivalent production, or 8,174 BOE per day, including 16 Bbl of oil per day and 48.9 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2016 , approximately 47% of our daily natural gas production, or 39.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.3 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2015 , approximately 61% of our daily natural gas production, or 46.4 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.6 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2016 , approximately 12% of our estimated total proved reserves, or 12.4 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 0.7 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +10 +Table of Contents +At December 31, 2016 , we had identified and engineered 431 gross ( 103.0 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 431 gross ( 103.0 net) locations identified for future drilling on our Haynesville acreage, 357 gross (50.1 net) locations have been identified within the 13,200 gross ( 6,400 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2016 , these potential future drilling locations included only 12 gross (4.0 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Haynesville and Middle Bossier Shales +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. +At December 31, 2016 , we had approximately 20,100 gross ( 12,500 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,200 gross ( 6,400 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,200 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2016 . +Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,100 net acres. We have identified 25 gross (19.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to just over 31%. +Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations +Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. +All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2016 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We have identified 71 gross ( 50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2016 and do not plan to drill any of these locations in 2017 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale +11 +Table of Contents +wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other asset areas in Northwest Louisiana and East Texas. At December 31, 2016 , we held an estimated 11,600 gross (9,200 net) leasehold and mineral acres by existing production in these areas. +Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale +During the year ended December 31, 2016 , we released all of our leasehold interests in Southwest Wyoming and adjacent areas in Utah and Idaho, which were originally leased as a part of a natural gas shale exploration prospect targeting the Meade Peak shale. As a result, we held no leasehold interests in these areas at December 31, 2016 . +Midstream Segment +The midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. Through the ownership and operation of these facilities, we improve our ability to manage costs and control the timing of bringing on new production, and we enhance the value received for our production. With the exception of a joint venture, which we controlled and which owned salt water disposal assets in Loving County, Texas, all of our midstream operations were wholly-owned by the Company at December 31, 2016 . In February 2017, we contributed our Delaware Midstream Assets to San Mateo. +Southeast New Mexico and West Texas — Delaware Basin +In late August 2016, we successfully completed and began operating the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico. The Black River Processing Plant has an inlet capacity of approximately 60 MMcf of natural gas per day, which is almost twice the size of the previous cryogenic processing plant we built in our Wolf asset area in Loving County, Texas (the “Wolf Processing Plant”) and subsequently sold to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Black River Processing Plant and associated gathering system was built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with priority one takeaway and processing services for our Rustler Breaks natural gas production. It may also provide additional income through the gathering and processing of third-party natural gas. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks. In addition, in late December 2016, we placed in service our initial salt water disposal well and associated salt water disposal facility and water gathering pipelines in our Rustler Breaks asset area. We disposed of over 800,000 Bbl of salt water during the well’s first two months of operation. +In our Wolf asset area in Loving County, Texas, we have oil, natural gas and salt water gathering systems that gather our oil, natural gas and water production and a small volume of third-party natural gas. We retained this three-pipeline system following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to EnLink in October 2015. The Loving County Processing System included the Wolf Processing Plant and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. We also retained our interest in commercial salt water disposal assets in Loving County. During 2016 , we disposed of approximately 10.2 million Bbl of salt water, including disposal of third-party salt water on a commercial basis. At February 22, 2017 , San Mateo had capacity to dispose of approximately 50,000 Bbl of salt water per day in the Wolf asset area. San Mateo is in the process of completing its third salt water disposal well and related disposal facility in the Wolf asset area, which is expected to be operational by the end of the first quarter of 2017 and which should increase the total salt water disposal capacity in the Wolf asset area to approximately 75,000 Bbl per day. +South Texas / Northwest Louisiana and East Texas +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases there and from third parties. We also have four non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo. +12 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2016, 2015 and 2014 . +Year Ended December 31, +2016 +2015 +2014 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +5,096 +4,492 +3,320 +Natural gas (Bcf) +30.5 +27.7 +15.3 +Total oil equivalent (MBOE) (1) +10,180 +9,109 +5,870 +Average daily production (BOE/d) (1) +27,813 +24,955 +16,082 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +41.19 +$ +45.27 +$ +87.37 +Oil, with realized derivatives (per Bbl) +$ +42.34 +$ +59.13 +$ +88.94 +Natural gas, without realized derivatives (per Mcf) +$ +2.66 +$ +2.71 +$ +5.08 +Natural gas, with realized derivatives (per Mcf) +$ +2.78 +$ +3.24 +$ +5.06 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +4.23 +$ +3.91 +(2) +$ +5.65 +Lease operating +$ +5.52 +$ +6.01 +(3) +$ +8.51 +(3) +Plant and other midstream services operating +$ +0.53 +$ +0.38 +$ +0.24 +Depletion, depreciation and amortization +$ +11.99 +$ +19.63 +$ +22.95 +General and administrative +$ +5.41 +$ +5.50 +$ +5.48 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(2) +$0.01 per BOE reclassified to third-party midstream services revenues due to our midstream business becoming a reportable segment in the third quarter of 2016. +(3) +$0.38 and $0.24 per BOE reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +3,805 +1,286 +— +5 +5,096 +Natural gas (Bcf) +12.2 +3.1 +14.3 +0.9 +30.5 +Total oil equivalent (MBOE) (3) +5,834 +1,813 +2,385 +148 +10,180 +Percentage of total annual net production +57.3 +% +17.8 +% +23.4 +% +1.5 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +10,395 +3,517 +— +12 +13,924 +Natural gas (MMcf/d) +33.3 +8.6 +39.1 +2.3 +83.3 +Total oil equivalent (BOE/d) +15,941 +4,952 +6,517 +403 +27,813 +Average Sales Prices (4) +Oil (per Bbl) +$ +41.76 +$ +39.49 +$ +— +$ +38.78 +$ +41.19 +Natural gas (per Mcf) +$ +3.15 +$ +3.11 +$ +2.17 +$ +2.27 +$ +2.66 +Total oil equivalent (per BOE) +$ +33.81 +$ +33.46 +$ +13.04 +$ +14.39 +$ +28.60 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +7.32 +$ +12.74 +$ +4.73 +$ +17.07 +$ +7.82 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +13 +Table of Contents +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +1,697 +2,789 +— +6 +4,492 +Natural gas (Bcf) +4.1 +5.7 +16.9 +1.0 +27.7 +Total oil equivalent (MBOE) (3) +2,379 +3,746 +2,822 +162 +9,109 +Percentage of total annual net production +26.1 +% +41.1 +% +31.0 +% +1.8 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +4,648 +7,642 +— +16 +12,306 +Natural gas (MMcf/d) +11.2 +15.7 +46.4 +2.6 +75.9 +Total oil equivalent (BOE/d) +6,518 +10,263 +7,731 +443 +24,955 +Average Sales Prices (4) +Oil (per Bbl) +$ +43.54 +$ +46.33 +$ +— +$ +43.68 +$ +45.27 +Natural gas (per Mcf) +$ +3.00 +$ +3.17 +$ +2.49 +$ +2.45 +$ +2.71 +Total oil equivalent (per BOE) +$ +36.21 +$ +39.35 +$ +14.97 +$ +15.69 +$ +30.56 +Production Costs (5) +Lease operating, transportation and processing (per BOE) (6) +$ +8.84 +$ +9.25 +$ +4.91 +$ +19.23 +$ +7.90 +_________________ +(1) +Includes one wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +(6) +Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2014 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +480 +2,834 +— +6 +3,320 +Natural gas (Bcf) +1.0 +6.0 +7.2 +1.1 +15.3 +Total oil equivalent (MBOE) (3) +653 +3,833 +1,201 +183 +5,870 +Percentage of total annual net production +11.1 +% +65.3 +% +20.5 +% +3.1 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +1,314 +7,764 +— +17 +9,095 +Natural gas (MMcf/d) +2.9 +16.4 +19.7 +2.9 +41.9 +Total oil equivalent (BOE/d) +1,790 +10,501 +3,290 +501 +16,082 +Average Sales Prices (4) +Oil (per Bbl) +$ +80.16 +$ +88.58 +$ +— +$ +91.24 +$ +87.37 +Natural gas (per Mcf) +$ +4.75 +$ +6.72 +$ +3.87 +$ +4.30 +$ +5.08 +Total oil equivalent (per BOE) +$ +66.41 +$ +75.99 +$ +23.27 +$ +27.92 +$ +62.64 +Production Costs (5) +Lease operating, transportation and processing (per BOE) (6) +$ +13.08 +$ +10.34 +$ +8.13 +$ +17.58 +$ +10.29 +_________________ +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +(6) +Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016. +Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have not drilled any new operated wells since the second quarter of 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, as compared to 24,955 BOE per day for the year ended December 31, 2015 . Our average daily oil production for the year ended December 31, 2016 was 13,924 Bbl of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year ended December 31, 2015 . Our average daily natural gas production for the year ended December 31, 2016 was 83.3 MMcf of natural gas per day, an increase of 10% from 75.9 MMcf of natural gas per day for the year ended December 31, 2015 . +Our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 increased 55% from our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 . This increased production was primarily due to our delineation and development operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, as compared to 16,082 BOE per day for the year ended December 31, 2014 . Our average daily oil production for the year ended December 31, 2015 was 12,306 Bbl of oil per day, an increase of 35% from 9,095 Bbl of oil per day for the year ended December 31, 2014 . Our average daily natural gas production for the year ended December 31, 2015 was 75.9 MMcf of natural gas per day, an increase of 81% from 41.9 MMcf of natural gas per day for the year ended December 31, 2014 . +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2016 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 72% in all wells that we operated at December 31, 2016. For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +261 +116.0 +51 +19.1 +312 +135.1 +South Texas: +Eagle Ford (2) +132 +111.1 +4 +4.0 +136 +115.1 +Northwest Louisiana/East Texas: +Haynesville +— +— +204 +19.8 +204 +19.8 +Cotton Valley (3) +2 +2.0 +79 +52.2 +81 +54.2 +Area Total +2 +2.0 +283 +72.0 +285 +74.0 +Total +395 +229.1 +338 +95.1 +733 +324.2 +__________________ +(1) +Includes 176 gross (50.5 net) wells acquired in February 2015 as part of the HEYCO Merger. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2016, 2015 and 2014 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +16 +Table of Contents +At December 31, (1) +2016 +2015 +2014 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +56,977 +45,644 +24,184 +Natural Gas (Bcf) (3) +292.6 +236.9 +267.1 +Total (MBOE) (4) +105,752 +85,127 +68,693 +Estimated proved developed reserves: +Oil (MBbl) +22,604 +17,129 +14,053 +Natural Gas (Bcf) (3) +126.8 +101.4 +102.8 +Total (MBOE) (4) +43,731 +34,037 +31,185 +Percent developed +41.4 +% +40.0 +% +45.4 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +34,373 +28,515 +10,131 +Natural Gas (Bcf) (3) +165.9 +135.5 +164.3 +Total (MBOE) (4) +62,021 +51,090 +37,508 +Standardized Measure (5) (in millions) +$ +575.0 +$ +529.2 +$ +913.3 +PV-10 (6) (in millions) +$ +581.5 +$ +541.6 +$ +1,043.4 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, and for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. +(3) +Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated properties in the Haynesville shale. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classified proved undeveloped reserves from our total proved reserves in 2016. +(5) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(6) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2016, 2015 and 2014 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2016, 2015 and 2014 were, in millions, $6.5 , $12.4 and $130.1 , respectively. +Our estimated total proved oil and natural gas reserves increase d 24% from 85.1 million BOE at December 31, 2015 to 105.8 million BOE at December 31, 2016 . We added 42.0 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2016, approximately 4.1 times our 2016 annual production of 10.2 million BOE. Our proved oil reserves grew 25% from approximately 45.6 million Bbl at December 31, 2015 to approximately 57.0 million Bbl at December 31, 2016 . Our proved natural gas reserves increase d 24% from 236.9 Bcf at December 31, 2015 to 292.6 Bcf at December 31, 2016 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2016. We incurred approximately 11.2 million BOE in net downward revisions to our proved reserves during 2016 as a result of the reclassification of certain proved undeveloped reserves to contingent resources, primarily due to the lower oil and natural gas prices used to estimate proved reserves at December 31, 2016, as compared to December 31, 2015. These contingent resources may be reclassified to proved undeveloped reserves in future periods should the oil and natural gas prices used to estimate proved oil and natural gas reserves improve from the prices at December 31, 2016. Our proved reserves to production ratio at December 31, 2016 was 10.4, an increase of 11% from 9.4 at December 31, 2015. +17 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increase d 9% from $529.2 million at December 31, 2015 to $575.0 million at December 31, 2016 . The PV-10 of our total proved oil and natural gas reserves increase d 7% from $541.6 million at December 31, 2015 to $581.5 million at December 31, 2016 . The increase in our Standardized Measure and PV-10 are primarily a result of our delineation and development operations in the Delaware Basin during 2016, which was partially impacted by the lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2016 , as compared to December 31, 2015 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2016 were $39.25 per Bbl and $2.48 per MMBtu, a decrease of 17% and 4% , respectively, as compared to average oil and natural gas prices of $46.79 per Bbl and $2.59 per MMBtu used to estimate proved reserves at December 31, 2015 . Our total proved reserves were made up of approximately 54% oil and 46% natural gas at December 31, 2016 and December 31, 2015 . +Our proved developed oil and natural gas reserves increase d 28% from 34.0 million BOE at December 31, 2015 to 43.7 million BOE at December 31, 2016 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 32% from 17.1 million Bbl at December 31, 2015 to 22.6 million Bbl at December 31, 2016 . Our proved developed natural gas reserves increase d 25% from 101.4 Bcf at December 31, 2015 to 126.8 Bcf at December 31, 2016 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2016 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2015 +34,037 +Extensions and discoveries +12,583 +Revisions of prior estimates +408 +Production +(10,180 +) +Conversion of proved undeveloped to proved developed +6,883 +As of December 31, 2016 +43,731 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d from 51.1 million BOE at December 31, 2015 to 62.0 million BOE at December 31, 2016 . Our proved undeveloped oil and natural gas reserves increased from 28.5 million Bbl and 135.5 Bcf, respectively, at December 31, 2015 to 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2016 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2016 within five years of booking these reserves. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2016 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2015 +51,090 +Extensions and discoveries +29,408 +Revisions of prior estimates +(11,594 +) +Conversion of proved undeveloped to proved developed +(6,883 +) +As of December 31, 2016 +62,021 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +The following table sets forth, since 2013, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2013 +2,944 +8.3 +4,334 +$ +115,699 +2014 +3,780 +44.7 +11,223 +201,950 +2015 +2,854 +23.4 +6,747 +104,989 +2016 +4,705 +13.1 +6,883 +94,579 +Total +14,283 +89.5 +29,187 +$ +517,217 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2016 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +46,873 +195.1 +79,388 +$ +446.0 +$ +451.0 +South Texas: +Eagle Ford (5) +10,066 +19.3 +13,298 +85.6 +86.6 +Northwest Louisiana/East Texas: +Haynesville +— +74.5 +12,414 +41.5 +42.0 +Cotton Valley (6) +38 +3.7 +652 +1.9 +1.9 +Area Total +38 +78.2 +13,066 +43.4 +43.9 +Total +56,977 +292.6 +105,752 +$ +575.0 +$ +581.5 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2016 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2016 were approximately $ 6.5 million . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational +19 +Table of Contents +methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 39 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2016 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +79,087 +33,699 +84,616 +60,613 +163,703 +94,312 +South Texas: +Eagle Ford +26,402 +23,682 +4,267 +4,095 +30,669 +27,777 +Northwest Louisiana/East Texas: +Haynesville +16,739 +9,088 +3,366 +3,364 +20,105 +12,452 +Cotton Valley +18,108 +16,078 +3,506 +2,993 +21,614 +19,071 +Area Total (1) +22,030 +19,761 +4,032 +3,517 +26,062 +23,278 +Total (2) +127,519 +77,142 +92,915 +68,225 +220,434 +145,367 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +(2) +During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2016 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2020 and beyond represents an immaterial amount of our overall undeveloped acreage. +20 +Table of Contents +Acres +Acres +Acres +Expiring 2017 +Expiring 2018 +Expiring 2019 +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +17,604 +7,987 +39,704 +25,294 +15,404 +9,086 +South Texas: +Eagle Ford +1,435 +1,375 +896 +753 +204 +156 +Northwest Louisiana/East Texas: +Haynesville +— +— +— +— +326 +324 +Cotton Valley +— +— +— +— +— +— +Area Total (2) +— +— +— +— +326 +324 +Total +19,039 +9,362 +40,600 +26,047 +15,934 +9,566 +__________________ +(1) +Approximately 54% of the acreage expiring in the next three years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes asset area in 2017 through our 2017 drilling activities or by paying an additional lease bonus, where applicable. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2016 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2016, 2015 and 2014 . +Year Ended December 31, +2016 +2015 +2014 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +44 +23.5 +53 +26.7 +89 +39.9 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +28 +15.6 +28 +17.5 +12 +10.6 +Dry +— +— +— +— +— +— +Total Wells +Productive +72 +39.1 +81 +44.2 +101 +50.5 +Dry +— +— +— +— +— +— +Marketing and Customers +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +21 +Table of Contents +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are based on various pipeline indices less any associated fees. When there is an opportunity to do so, we may have our natural gas processed at our or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the years ended December 31, 2016, 2015 and 2014 , we had three significant purchasers that accounted for approximately 48% , 59% and 68% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +22 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions, as well as drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering, processing and compression opportunities, as well as salt water disposal activities in the areas in which we operate. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated, and we can give no assurance that the current less stringent regulatory approach of FERC will continue. +23 +Table of Contents +In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil gathering facilities are also exempt from FERC’s jurisdiction under the Interstate Commerce Act. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and that the crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. +The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, as amended. In recent years, pursuant to these laws and, in addition, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking (NPRM) that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but has yet to publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +24 +Table of Contents +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management, or the BLM, with respect to federal acreage). +Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have also been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is +25 +Table of Contents +possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the Environmental Protection Agency, or the EPA, has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2016 , we owned and operated twelve underground injection wells and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and +26 +Table of Contents +operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation +27 +Table of Contents +requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2016 , we had 165 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, land, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Compensation Committee, Corporate Governance Committee, Executive Committee and Nominating Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +Item 1A. Risk Factors. +Risks Related to the Oil and Natural Gas Industry and Our Business +Our Success Is Dependent on the Prices of Oil and Natural Gas. Continued Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. +The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2016, the average price of oil was $43.40 per Bbl, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $2.55 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Starting in February and March of 2016, respectively, oil and natural gas prices began to increase from their most recent lows. Oil prices increased 106% from $26.21 per Bbl in mid-February 2016 to $54.06 per Bbl in late December 2016, and natural gas prices increased 140% from $1.64 per MMBtu in early March 2016 to $3.93 per MMBtu in late December 2016. +28 +Table of Contents +Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines caused us to recognize full-cost ceiling impairments in each of the quarters of 2015 and in the first two quarters of 2016, and should prices decline again, we may recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.” +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• +the domestic and foreign supply of, and demand for, oil and natural gas; +• +the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; +• +the prices and availability of competitors’ supplies of oil and natural gas; +• +the price and quantity of foreign imports; +• +the impact of U.S. dollar exchange rates on oil and natural gas prices; +• +domestic and foreign governmental regulations and taxes; +• +speculative trading of oil and natural gas futures contracts; +• +the availability, proximity and capacity of gathering, processing and transportation systems for natural gas; +• +the availability of refining capacity; +• +the prices and availability of alternative fuel sources; +• +weather conditions and natural disasters; +• +political conditions in or affecting oil and natural gas producing regions or countries, including the United States, Middle East, South America and Russia; +• +the continued threat of terrorism and the impact of military action and civil unrest; +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; +• +the level of global oil and natural gas inventories and exploration and production activity; +• +the impact of energy conservation efforts; +• +technological advances affecting energy consumption; and +• +overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain at economically unattractive levels for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +29 +Table of Contents +Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +We may sell additional equity securities or issue additional debt securities to raise capital. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our estimated proved oil and natural gas reserves; +• +the amount of oil and natural gas we produce from existing wells; +• +the prices at which we sell our production; +• +the costs of developing and producing our oil and natural gas reserves; +• +the costs of constructing, operating and maintaining our midstream facilities; +• +our ability to acquire, locate and produce new reserves; +• +the ability and willingness of banks to lend to us; and +• +our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as further decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain exploration opportunities. Alternatively, to fund acquisitions, increase our rate of growth, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. +Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +30 +Table of Contents +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• +general economic and industry conditions, including the prices received for oil and natural gas; +• +shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• +potential drainage of oil and natural gas from our properties by adjacent operators; +• +loss of or damage to oilfield development and service tools; +• +accidents, equipment failures or mechanical problems; +• +title defects of the underlying properties; +• +increases in severance taxes; +• +adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• +domestic and foreign governmental regulations; and +• +proximity to and capacity of gathering, processing and transportation facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us and our service providers. For example, risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +• +landing our wellbore in the desired drilling zone; +• +staying in the desired drilling zone while drilling horizontally through the formation; +• +running our casing the entire length of the wellbore; +• +fracture stimulating the planned number of stages; and +• +being able to run tools and other equipment consistently through the horizontal wellbore. +If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 22, 2017 , our borrowing base was $400.0 million , and we had no outstanding borrowings under, and approximately $0.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement. We could be required to repay a portion of any outstanding bank debt to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions. +Our Credit Agreement and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• +incur or guarantee additional debt or issue certain types of preferred stock; +31 +Table of Contents +• +pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• +consolidate, merge or transfer all or substantially all of our assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. Low oil and natural gas prices or any decline in the prices of oil or natural gas may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement or indenture is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +We May Not Be Able to Generate Sufficient Cash to Service All of Our Indebtedness and May Be Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May Not Be Successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We May Incur Additional Indebtedness, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. +At February 22, 2017 , we had available borrowings of approximately $399.2 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties, and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. +32 +Table of Contents +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement), we may incur significant amounts of additional indebtedness, including under our Credit Agreement or through the issuance of additional notes, in order to fund acquisitions, develop our properties or invest in certain exploration opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• +requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• +increasing our vulnerability to general adverse economic and industry conditions; +• +placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• +restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• +increasing the risk that we may default on our debt obligations. +Our Credit Rating May Be Downgraded, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations. +As of February 22, 2017 , our corporate credit rating from Standard & Poor’s Rating Services was “B” and our corporate credit rating from Moody’s Investors Service was “B2.” We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering and processing, including: +• +natural disasters; +• +adverse weather conditions; +• +loss of drilling fluid circulation; +• +blowouts where oil or natural gas flows uncontrolled at a wellhead; +• +cratering or collapse of the formation; +• +pipe or cement leaks, failures or casing collapses; +• +damage to pipelines, processing plants and disposal wells and associated facilities; +• +fires or explosions; +• +releases of hazardous substances or other waste materials that cause environmental damage; +• +pressures or irregularities in formations; and +• +equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +33 +Table of Contents +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana and East Texas. In 2015 and 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. As a result, for the year ended December 31, 2016 , approximately 57% of our total oil and natural gas production, including approximately 75% of our average daily oil production, was attributable to our properties in the Delaware Basin and approximately 18% of our total oil and natural gas production, including approximately 25% of our average daily oil production, was attributable to our properties in the Eagle Ford shale. At December 31, 2016 , approximately 75% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. We expect that a significant portion of our operations in 2017 will be in the Delaware Basin. +The industry focus on the Delaware Basin may adversely impact our ability to transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil and condensate trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, the weather conditions and freezing temperatures have resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In recent years, certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we +34 +Table of Contents +may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should low oil or natural gas prices continue or should oil and natural gas prices decline further, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the judgment of the persons preparing the estimate; and +• +the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be +35 +Table of Contents +redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +actual costs and timing of development and production expenditures; +• +the amount and timing of actual production; and +• +changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 59% of Our Total Proved Reserves at December 31, 2016 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. +At December 31, 2016 , approximately 59% of our total proved reserves were undeveloped and less than 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms and seasonal conditions. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. +At December 31, 2016 , we had leasehold interests in approximately 44,975 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2020 . Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party +36 +Table of Contents +leases may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic and geological data can be expensive to license or obtain and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Similarly, our midstream business, and particularly the success of the Joint Venture, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. +Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +37 +Table of Contents +The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue. +The unavailability of satisfactory oil, natural gas and natural gas liquids gathering, processing and transportation arrangements may hinder our access to oil, natural gas and natural gas liquids markets or delay production from our wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for, and supply of, oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of the Joint Venture, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas occasionally, which would decrease the volumes sold from our wells. +The disruption of our or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and natural gas liquids. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas and our Eagle Ford shale acreage in South Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering, disposal or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2017 . If we were required to shut in our production or flare our natural gas for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third-Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. +We derive most of our revenues from the sale of our oil, natural gas and natural gas liquids to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows. +Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +38 +Table of Contents +Our Natural Gas Processing Operations Are Subject to Operational Risks, Which Could Result in Significant Damages and the Loss of Revenue. +The Joint Venture owns, and we operate, the Black River Processing Plant. There are significant risks associated with the operation of cryogenic natural gas processing plants. Natural gas and natural gas liquids are volatile and explosive and may include carcinogens. Damage to or improper operation of a cryogenic natural gas processing plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells located in the Rustler Breaks asset area. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +We Have Entered into Certain Long-Term Contracts That Require Us to Pay Fees to Our Service Providers Based on Minimum Volumes Regardless of Actual Volume Throughput and That May Limit Our Ability to Use Other Service Providers. +In connection with the sale of the Loving County Processing System in October 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement covering the anticipated natural gas production from a significant portion of our acreage in the Wolf asset area in the Delaware Basin (the “Wolf Gathering Agreement”). In addition, in connection with the formation of the Joint Venture, we entered into certain 15-year fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements covering the Rustler Breaks and Wolf asset areas and a natural gas processing agreement covering the Rustler Breaks asset area (collectively, the “Joint Venture Agreements”). We are also subject to a firm natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, which agreement expires in September 2017. In each of these agreements we have provided certain minimum volume commitments. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to fulfill our obligations under these agreements. These agreements obligate us to pay fees on minimum volumes to our service providers (including the Joint Venture) regardless of actual throughput. As of December 31, 2016, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $12.9 million over the term of the agreements (excluding the Joint Venture Agreements, which were entered into in 2017). If we have insufficient production to meet the minimum volumes, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to the Wolf Gathering Agreement and the Joint Venture Agreements, we have dedicated our current and future leasehold interests in the Wolf and Rustler Breaks asset areas to EnLink or the Joint Venture, as applicable. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers in the Wolf and Rustler Breaks asset areas, even if such service providers are able to offer us more favorable pricing or more efficient service. +Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. +The operations of our midstream business, including the Joint Venture, and the operations of the third parties on whom we rely for gathering, processing and transportation services, are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. Substantial costs may be incurred in order to comply with existing laws and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new laws and regulations become applicable to operations, these changes may affect the costs that we pay for such services or the results of our midstream business, including the Joint Venture. Similarly, a failure to comply with such laws and regulations by us or the parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” +We Have Limited Control over Activities on Properties We Do Not Operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to Chesapeake in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• +timing and amount of capital expenditures; +• +the operator’s expertise and financial resources; +39 +Table of Contents +• +the rate of production of reserves, if any; +• +approval of other participants in drilling wells; and +• +selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +We Conduct a Portion of Our Operations through Joint Ventures, Which Subjects Us to Additional Risks That Could Have a Material Adverse Effect on the Success of These Operations, Our Financial Position, Results of Operations or Cash Flows. +We own and operate substantially all of our midstream assets in the Delaware Basin through the Joint Venture, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for the Joint Venture and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for the joint ventures’ liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows. +We Do Not Own All of the Land on Which Our Midstream Assets Are Located, Which Could Disrupt Our Operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Construction of Midstream Projects Subjects Us to Risks of Construction Delays, Cost Over-Runs, Limitations on Our Growth and Negative Effects on Our Financial Condition, Results of Operations, Cash Flows and Liquidity. +From time-to-time we, through the Joint Venture or otherwise, plan and construct midstream projects, some of which will take a number of months before commercial operation, such as the Joint Venture’s expansion of the Black River Processing Plant or the drilling of additional salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of salt water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +40 +Table of Contents +A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. +Before acquiring oil and natural gas properties, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. +If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the mineral interest owner or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. +It is not our practice in all acquisitions of oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in +41 +Table of Contents +assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows. +We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have: +• +downward adjustments to our estimated proved reserves; +• +increases in our estimates of development costs; or +• +deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. +During the first and second and quarters of 2016, our net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded impairment charges totaling $158.6 million , exclusive of tax effect, to our net capitalized costs for the year ended December 31, 2016 . For further discussion of the full-cost ceiling impairment at December 31, 2016 , see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Expenses.” A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. As of February 22, 2017 , we had approximately 70% and 50% of our estimated remaining 2017 oil and natural gas production, respectively, hedged. We currently have no hedges in place for natural gas liquids and no hedges in place for natural gas beyond 2017; however, we have a portion of our anticipated oil volumes hedged in 2018. +42 +Table of Contents +An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience with respect to our production. As such, we will be exposed to any increase in such differentials. +We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. In addition to expenditures required in order for us to comply with such laws and regulations, these expenditures could also include payments for: +• +personal injuries; +• +property damage; +• +containment and clean-up of oil and other spills; +• +management and disposal of hazardous materials; +• +remediation, clean-up costs and natural resource damages; and +• +other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or facilities are located, or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered species could prohibit drilling in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production activities, each of which could have an adverse impact on our ability to develop and produce our reserves. +We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +43 +Table of Contents +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The passage of any legislation or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. +Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and natural gas liquids from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. The EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under certain circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. The EPA has issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Also at the federal level, the BLM issued final rules to regulate hydraulic fracturing on federal lands in March 2015, although these rules were struck down by a federal court in Wyoming in June 2016. An appeal of the decision is pending. +In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas, New Mexico and Wyoming have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Moreover, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. +The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, monitoring of greenhouse gas emissions from petroleum and natural gas systems commenced on January 1, 2011, with the first annual reports required to be filed in 2012. In October 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gas monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil and natural gas wells. The revisions also include the addition of well identification reporting requirements for certain facilities. There were attempts +44 +Table of Contents +at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Finally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement, if ratified, establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. Any future international agreements, federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs, adversely affecting our profits, and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. +On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. Further, in May 2016, the EPA issued final NSPS governing methane emissions from the oil and natural gas industry as well as source determination standards for determining when oil and natural gas sources should be aggregated for CAA permitting and compliance purposes. The NSPS for methane extends the 2012 NSPS to completions of hydraulically fractured oil and natural gas wells, equipment leaks, pneumatic pumps and natural gas compressors. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural gas facilities. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. These rules are expected to result in an increase to our operating costs and changes in our operations. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs on our operations. +A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the Interstate Commerce Act. We believe that the crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. However, whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of +45 +Table of Contents +our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. The nature of our gathering facilities is such that we have not yet been regulated by FERC. It is possible, however, that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. +On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through the Joint Venture or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including +46 +Table of Contents +our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. Certain of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +Information Technology Systems Implementation Issues Could Disrupt Our Internal Operations, Increase Our Costs and Could Have a Material Adverse Effect on Our Financial Results or Our Ability to Report Our Financial Results. +We are currently in the process of implementing new information technology software systems to replace certain of our legacy systems, including our accounting and land systems. As a part of this effort, we are transitioning data and changing certain processes, which will require changes to our internal control over financial reporting. This implementation process may be more expensive, time consuming and resource intensive than planned. Any disruptions that may occur in the implementation or operation of these systems updates or any future systems that we implement could increase our expenses and have a material adverse effect on our ability to report in an accurate and timely manner our financial position, results of operations and cash flows and to otherwise operate our business. +A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or Financial Loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. +While we have not experienced any material losses due to cyber-attacks, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Risks Relating to Our Common Stock +The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2016 , our stock price fluctuated between a high of $27.71 and a low of $11.13 . In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• +our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• +quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +47 +Table of Contents +• +changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• +speculation in the press or investment community; +• +announcement or consummation of acquisitions or dispositions by us; +• +public reaction to our press releases, announcements and filings with the SEC; +• +sales of our common stock by us or shareholders, or the perception that such sales may occur; +• +general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and natural gas liquids; +• +the realization of any of the risk factors presented in this Annual Report; +• +the recruitment or departure of key personnel; +• +commencement of or involvement in litigation; +• +the success of our exploration and development operations, our midstream business and the marketing of any oil, natural gas and natural gas liquids we produce; +• +changes in market valuations of companies similar to ours; and +• +domestic and international economic, legal and regulatory factors unrelated to our performance. +If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Further, our remediation efforts may not enable us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. +We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. +Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +48 +Table of Contents +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• +authorization for our Board of Directors to issue preferred stock without shareholder approval; +• +a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• +the prohibition of cumulative voting in the election of directors; and +• +a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +Our Directors and Executive Officers Own a Significant Percentage of Our Equity, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. +As of February 22, 2017 , our directors and executive officers beneficially owned approximately 12% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 13 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +49 +Table of Contents +We are a party to several lawsuits encountered in the ordinary course of our business. While the ultimate outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on our financial condition, results of operations or cash flows. +Item 4. Mine Safety Disclosures. +Not applicable. +50 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 24, 2017, we had 100,034,559 shares of common stock outstanding held by approximately 300 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated. +2016 +2015 +High +Low +High +Low +First Quarter +$ +20.94 +$ +11.13 +$ +25.08 +$ +18.28 +Second Quarter +$ +25.54 +$ +18.03 +$ +29.90 +$ +22.01 +Third Quarter +$ +24.71 +$ +18.56 +$ +26.07 +$ +19.08 +Fourth Quarter +$ +27.71 +$ +20.45 +$ +28.25 +$ +18.87 +On February 24, 2017, the last reported sales price of our common stock on the NYSE was $24.42 per share. +Dividend Policy +We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends on our common stock. During the years ended December 31, 2016 and 2015 , we did not pay dividends to holders of our common stock. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2016 . +Equity Compensation Plan Information +Plan Category +Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights +Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights +Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1) (2) +2,872,954 +$ +15.59 +3,963,427 +Equity compensation plans not approved by security holders +— +— +— +Total +2,872,954 +$ +15.59 +3,963,427 +__________________ +(1) +Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. +(2) +The Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015 and approved by our shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8 to the consolidated financial statements in this Annual Report. +51 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from February 2, 2012, the date our common stock began trading on the NYSE, through December 31, 2016 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +52 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2016, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs +Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2016 to October 31, 2016 +1,131 +$ +23.66 +— +— +November 1, 2016 to November 30, 2016 +1,288 +21.45 +— +— +December 1, 2016 to December 31, 2016 +1,306 +25.65 +— +— +Total +3,725 +$ +23.59 +— +— +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. +53 +Table of Contents +Item 6. Selected Financial Data. +The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2016 and selected consolidated balance sheet and cash flow data at December 31, 2016 , 2015 , 2014 , 2013 and 2012 . You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report. The financial information included in this Annual Report may not be indicative of our future results of operations, financial condition or cash flows. +Year Ended December 31, +2016 +2015 +2014 +2013 +2012 +(In thousands, except per share data) +Statement of operations data: +Revenues +Oil and natural gas revenues +$ +291,156 +$ +278,340 +$ +367,712 +$ +269,030 +$ +155,998 +Third-party midstream services revenue +5,218 +1,864 +1,213 +207 +183 +Realized gain (loss) on derivatives +9,286 +77,094 +5,022 +(909 +) +13,960 +Unrealized (loss) gain on derivatives +(41,238 +) +(39,265 +) +58,302 +(7,232 +) +(4,802 +) +Total revenues +264,422 +318,033 +432,249 +261,096 +165,339 +Expenses +Production taxes, transportation and processing (1) +43,046 +35,650 +33,172 +20,973 +11,672 +Lease operating (2) +56,202 +54,704 +49,945 +37,971 +27,868 +Plant and other midstream services operating +5,389 +3,489 +1,408 +749 +316 +Depletion, depreciation and amortization +122,048 +178,847 +134,737 +98,395 +80,454 +Accretion of asset retirement obligations +1,182 +734 +504 +348 +256 +Full-cost ceiling impairment +158,633 +801,166 +— +21,229 +63,475 +General and administrative +55,089 +50,105 +32,152 +20,779 +14,543 +Total expenses +441,589 +1,124,695 +251,918 +200,444 +198,584 +Operating (loss) income +(177,167 +) +(806,662 +) +180,331 +60,652 +(33,245 +) +Other income (expense) +Net gain (loss) on asset sales and inventory impairment +107,277 +908 +— +(192 +) +(485 +) +Interest expense +(28,199 +) +(21,754 +) +(5,334 +) +(5,687 +) +(1,002 +) +Other (expense) income (3) +(4 +) +616 +132 +18 +42 +Total other income (expense) +79,074 +(20,230 +) +(5,202 +) +(5,861 +) +(1,445 +) +Net (loss) income +(97,057 +) +(679,524 +) +110,754 +45,094 +(33,261 +) +Net (income) loss attributable to non-controlling interest in subsidiaries +(364 +) +(261 +) +17 +— +— +Net (loss) income attributable to +Matador Resources Company shareholders +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +$ +45,094 +$ +(33,261 +) +Earnings (loss) per common share +Basic +Class A (4) +$ +(1.07 +) +$ +(8.34 +) +$ +1.58 +$ +0.77 +$ +(0.62 +) +Class B (4) +$ +— +$ +— +$ +— +$ +— +$ +(0.35 +) +Diluted +Class A (4) +$ +(1.07 +) +$ +(8.34 +) +$ +1.56 +$ +0.77 +$ +(0.62 +) +Class B (4) +$ +— +$ +— +$ +— +$ +— +$ +(0.35 +) +Class B dividend declared, per share (4) +$ +— +$ +— +$ +— +$ +— +$ +0.27 +__________________ +(1) +$0.1 million was reclassified to third-party midstream services revenues for the year ended December 31, 2015 due to our midstream business becoming a reportable segment in the third quarter of 2016. There were no such reclassifications made in any other periods presented. +(2) +$3.5 million, $1.4 million, $0.7 million and $0.3 million were reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016. +(3) +$1.7 million, $1.2 million, $0.2 million and $0.2 million were reclassified to midstream services revenues for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016. +(4) +Our Class B common stock converted into Class A common stock upon the consummation of our initial public offering on February 7, 2012 and the Class A common stock then became the only class of common stock authorized. The term “Class A common stock” refers to shares of our Class A +54 +Table of Contents +common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering. +At December 31, +2016 +2015 +2014 +2013 +2012 +(In thousands) +Balance sheet data: +Cash and cash equivalents +$ +212,884 +$ +16,732 +$ +8,407 +$ +6,287 +$ +2,095 +Restricted cash +1,258 +44,357 +609 +— +— +Certificates of deposit +— +— +— +— +230 +Net property and equipment +1,184,525 +1,012,406 +1,322,072 +845,877 +591,090 +Total assets +1,464,665 +1,140,861 +1,434,490 +890,330 +632,029 +Current liabilities +169,505 +136,830 +142,036 +100,327 +96,492 +Long-term liabilities +603,715 +515,072 +425,913 +221,079 +156,433 +Total Matador Resources Company shareholders’ equity +$ +690,125 +$ +488,003 +$ +866,408 +$ +568,924 +$ +379,104 +Year Ended December 31, +2016 +2015 +2014 +2013 +2012 +(In thousands) +Other financial data: +Net cash provided by operating activities +$ +134,086 +$ +208,535 +$ +251,481 +$ +179,470 +$ +124,228 +Net cash used in investing activities +(405,640 +) +(425,154 +) +(570,531 +) +(366,939 +) +(306,916 +) +Oil and natural gas properties capital expenditures +(379,067 +) +(432,715 +) +(560,849 +) +(363,192 +) +(300,689 +) +Expenditures for other property and equipment +(74,845 +) +(64,499 +) +(9,152 +) +(3,977 +) +(7,332 +) +Net cash provided by financing activities +467,706 +224,944 +321,170 +191,661 +174,499 +Adjusted EBITDA (1) +$ +157,928 +$ +223,155 +$ +262,943 +$ +191,771 +$ +115,923 +__________________ +(1) +Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “ – Non-GAAP Financial Measures” below. +Non-GAAP Financial Measures +We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +55 +Table of Contents +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2016 +2015 +2014 +2013 +2012 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net (Loss) Income: +Net (loss) income attributable to Matador Resources Company shareholders +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +$ +45,094 +$ +(33,261 +) +Interest expense +28,199 +21,754 +5,334 +5,687 +1,002 +Total income tax (benefit) provision +(1,036 +) +(147,368 +) +64,375 +9,697 +(1,430 +) +Depletion, depreciation and amortization +122,048 +178,847 +134,737 +98,395 +80,454 +Accretion of asset retirement obligations +1,182 +734 +504 +348 +256 +Full-cost ceiling impairment +158,633 +801,166 +— +21,229 +63,475 +Unrealized loss (gain) on derivatives +41,238 +39,265 +(58,302 +) +7,232 +4,802 +Stock-based compensation expense +12,362 +9,450 +5,524 +3,897 +140 +Net (gain) loss on asset sales and inventory impairment +(107,277 +) +(908 +) +— +192 +485 +Adjusted EBITDA +$ +157,928 +$ +223,155 +$ +262,943 +$ +191,771 +$ +115,923 +Year Ended December 31, +2016 +2015 +2014 +2013 +2012 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities +$ +134,086 +$ +208,535 +$ +251,481 +$ +179,470 +$ +124,228 +Net change in operating assets and liabilities +(1,809 +) +(8,980 +) +5,978 +6,210 +(9,307 +) +Interest expense, net of non-cash portion +27,051 +20,902 +5,334 +5,687 +1,002 +Current income tax (benefit) provision +(1,036 +) +2,959 +133 +404 +— +Net (income) loss attributable to non-controlling interest in subsidiaries +(364 +) +(261 +) +17 +— +— +Adjusted EBITDA +$ +157,928 +$ +223,155 +$ +262,943 +$ +191,771 +$ +115,923 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +Overview +We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations primarily, as of February 17, 2017, through San Mateo in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. +56 +Table of Contents +2016 Operational Highlights +During the year ended December 31, 2016 , we completed and began producing oil and natural gas from 40 gross (35.6 net) operated and 15 gross (1.4 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or in Northwest Louisiana and East Texas during 2016, although we did participate in the drilling and completion of 15 gross (2.1 net) non-operated Haynesville shale wells and two gross (less than 0.1 net) non-operated Eagle Ford shale wells that began producing in 2016. +At January 1, 2016, we were operating three drilling rigs in the Delaware Basin in Southeast New Mexico and West Texas, and we operated these drilling rigs in certain of our various asset areas in the Delaware Basin throughout most of 2016. We contracted a fourth drilling rig in late August 2016 to begin drilling our first salt water disposal well in our Rustler Breaks asset area in Eddy County, New Mexico. After we finished drilling that well, we moved the rig to our Wolf asset area in Loving County, Texas to drill a third salt water disposal well there. In late November 2016, we elected to move this fourth drilling rig back to our Rustler Breaks asset area to begin drilling oil and natural gas wells there. At December 31, 2016 and February 22, 2017 we continued to operate four drilling rigs in the Delaware Basin, including two rigs in our Rustler Breaks asset area, one rig in our Wolf asset area and one rig in our Ranger and Arrowhead asset areas in Lea and Eddy Counties, New Mexico. The vast majority of our 2016 capital expenditures of $454.4 million were directed to the delineation and development of our leasehold position in the Delaware Basin, to the development of certain midstream assets to support our operations there and to the acquisition of additional leasehold interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were directed to the installation of pumping units and other facilities on certain of our Eagle Ford shale wells in South Texas and to our participation in several non-operated wells drilled and completed in the Eagle Ford and Haynesville shales throughout 2016, as noted above. +We increased our leasehold position significantly in the Delaware Basin during 2016. At December 31, 2016 , we held approximately 163,700 gross ( 94,300 net) acres in the Permian Basin in Southeast New Mexico and West Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. Between January 1, 2017 and February 22, 2017 , we acquired approximately 13,900 gross (8,200 net) leasehold and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around our existing acreage in the Delaware Basin. This brought our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres, almost all of which was located in the Delaware Basin. +Our oil production, natural gas production and average daily oil equivalent production during 2016 were the best in the Company’s history. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, an increase of 12% as compared to 24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, for the year ended December 31, 2015 . Our average daily oil production in 2016 of 13,924 Bbl of oil per day increased 13% , as compared to an average daily oil production of 12,306 Bbl of oil per day in 2015 . This increase in oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not drilled any new operated wells since the second quarter of 2015. Our average daily natural gas production of 83.3 MMcf per day for the year ended December 31, 2016 increased 10% from 75.9 MMcf per day for the year ended December 31, 2015 . This increase in natural gas production was primarily attributable to increased natural gas production associated with our operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana in the latter half of 2015 and into 2016. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2016 , as compared to 49% for the year ended December 31, 2015 . +For the year ended December 31, 2016 , our oil and natural gas revenues were $291.2 million , an increase of 5% from oil and natural gas revenues of $278.3 million for the year ended December 31, 2015 . Our oil revenues and natural gas revenues increased 3% and 8% to approximately $209.9 million and $81.2 million , respectively, as a result of the increases in oil and natural gas production for the year ended December 31, 2016 as noted above, as compared to $203.4 million and $75.0 million , respectively, for the year ended December 31, 2015 . The increase in both oil and natural gas production in 2016 helped to mitigate the impacts of somewhat lower realized weighted average oil and natural gas prices of $41.19 per Bbl and $2.66 per Mcf in 2016, respectively, as compared to $45.27 per Bbl and $2.71 per Mcf in 2015, respectively. +We reported a net loss of approximately $97.4 million , or $1.07 per diluted common share on a GAAP basis for the year ended December 31, 2016 , as compared to a net loss of $679.8 million , or $8.34 per diluted common share, for the year ended December 31, 2015 . Our net loss and net loss per diluted common share on a GAAP basis were significantly impacted by full-cost ceiling impairments of $158.6 million and $801.2 million for the years ended December 31, 2016 and 2015 , respectively, as a result of substantial declines in oil and natural gas prices throughout 2015 and 2016. Adjusted EBITDA for the year ended December 31, 2016 was $157.9 million , as compared to Adjusted EBITDA of $223.2 million reported for the year ended December 31, 2015 . This decrease in Adjusted EBITDA resulted, in part, from the lower weighted average oil and natural gas +57 +Table of Contents +prices realized in 2016, but was primarily attributable to lower realized hedging revenues of $9.3 million in 2016, as compared to $77.1 million in 2015. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +At December 31, 2016 , our estimated total proved oil and natural gas reserves were 105.8 million BOE, an all-time high for the Company, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, with a Standardized Measure of $575.0 million and a PV-10 of $581.5 million . At December 31, 2015 , our estimated proved oil and natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, with a Standardized Measure of $529.2 million and a PV-10 of $541.6 million . Our estimated total proved reserves of 105.8 million BOE at December 31, 2016 represented a 24% year-over-year increase, as compared to 85.1 million BOE at December 31, 2015 . Our estimated proved oil reserves of 57.0 million Bbl at December 31, 2016 increased 25% , as compared to 45.6 million Bbl at December 31, 2015 . Our proved oil and natural gas reserves in the Delaware Basin increased 68% to 79.4 million BOE at December 31, 2016 , as compared to 47.1 million BOE at December 31, 2015 , as a result of our ongoing delineation and development operations in the Delaware Basin. At December 31, 2016 , approximately 75% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 49% to 46.9 million Bbl at December 31, 2016 , as compared to 31.4 million Bbl at December 31, 2015 . Proved oil reserves comprised 54% of our total proved reserves at both December 31, 2016 and December 31, 2015 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” +2017 Midstream Joint Venture +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the next five years. We continue to operate the Delaware Midstream Assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will continue to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +2017 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2017 . We plan to operate four contracted drilling rigs in the Delaware Basin during the first quarter of 2017 and expect to add a fifth drilling rig in the Delaware Basin in the second quarter of 2017 . Our 2017 estimated capital expenditure budget consists of $370 to $390 million for drilling, completions, facilities and infrastructure and $56 to $64 million for midstream capital expenditures, which represents our 51% share of an estimated 2017 capital expenditure budget of $110 to $125 million for San Mateo. Substantially all of our 2017 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2017 Delaware Basin drilling program will focus on the continued development of the Wolf and Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested zones in the Wolf and Rustler Breaks asset areas during 2017. +We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2017. These expenditures are opportunity-specific and per-acre prices can vary significantly based on the prospect. As a result, it is difficult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2017. +At December 31, 2016 , we had $212.9 million in cash (excluding restricted cash) and $399.2 million in undrawn borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit). As a result, we expect to fund our capital expenditures for 2017 through a combination of cash on hand, operating cash flows, proceeds we received in connection with the formation of the Joint Venture and borrowings under our Credit Agreement (assuming availability under our borrowing base). We may also consider funding a portion of our 2017 capital expenditures through additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. The aggregate amount of capital we expend may fluctuate materially based on market conditions, +58 +Table of Contents +the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs of our midstream activities, other opportunities that may become available to us and our ability to obtain capital. +59 +Table of Contents +Revenues +Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices. +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2016 +2015 +2014 +Operating Data: +Revenues (in thousands): (1) +Oil +$ +209,908 +$ +203,355 +$ +290,026 +Natural gas +81,248 +74,985 +77,686 +Total oil and natural gas revenues +291,156 +278,340 +367,712 +Third-party midstream services revenues +5,218 +1,864 +1,213 +Realized gain on derivatives +9,286 +77,094 +5,022 +Unrealized (loss) gain on derivatives +(41,238 +) +(39,265 +) +58,302 +Total revenues +$ +264,422 +$ +318,033 +$ +432,249 +Net Production Volumes: (1) +Oil (MBbl) +5,096 +4,492 +3,320 +Natural gas (Bcf) +30.5 +27.7 +15.3 +Total oil equivalent (MBOE) (2) +10,180 +9,109 +5,870 +Average daily production (BOE/d) (2) +27,813 +24,955 +16,082 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +41.19 +$ +45.27 +$ +87.37 +Oil, with realized derivatives (per Bbl) +$ +42.34 +$ +59.13 +$ +88.94 +Natural gas, without realized derivatives (per Mcf) +$ +2.66 +$ +2.71 +$ +5.08 +Natural gas, with realized derivatives (per Mcf) +$ +2.78 +$ +3.24 +$ +5.06 +________________ +(1) +We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues. +(2) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015 +Oil and natural gas revenues . Our oil and natural gas revenues increase d $12.8 million to $291.2 million , or an increase of 5% , for the year ended December 31, 2016 , as compared to $278.3 million for the year ended December 31, 2015 . Our oil revenues increase d $6.6 million , or an increase of 3% , to $209.9 million for the year ended December 31, 2016 , as compared to $203.4 million for the year ended December 31, 2015 . The increase in oil revenues resulted from the 13% increase in our oil production to 5.1 million Bbl of oil for the year ended December 31, 2016 , or about 13,924 Bbl of oil per day, as compared to 4.5 million Bbl of oil, or about 12,306 Bbl of oil per day, for the year ended December 31, 2015 . This increase d oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the Eagle Ford shale, where we have not drilled any new operated wells since the second quarter of 2015. The increase in oil revenues was partially impacted by a lower weighted average oil price realized for the year ended December 31, 2016 of $41.19 per Bbl, as compared to $45.27 per Bbl realized for the year ended December 31, 2015 . Our natural gas revenues increase d $6.3 million , or an increase of 8% , to $81.2 million for the year ended December 31, 2016 , as compared to $75.0 million for the year ended December 31, 2015 . The increase in natural gas revenues resulted from the 10% increase in our natural gas production to 30.5 Bcf for the year ended December 31, 2016 , as compared to 27.7 Bcf for the year ended December 31, 2015 . The increased natural gas production was primarily attributable to our ongoing delineation and development drilling in the Delaware Basin, which offset declining natural gas production in the Eagle Ford and Haynesville shales where we have significantly reduced our activity since late 2014 and early 2015. The increase in natural gas revenues was partially impacted by a lower weighted average natural gas price realized for the year ended December 31, 2016 of $2.66 per Mcf, as compared to $2.71 per Mcf realized for the year ended December 31, 2015 . +Third-party midstream services revenues. During the third quarter of 2016, our midstream operations became a reportable business segment under GAAP. Our third-party midstream services revenues were previously included in other income. Third-party midstream services revenues are primarily those revenues from midstream operations related to third parties, including working interest owners in our operated wells; all midstream services revenues associated with our production are eliminated in consolidation. Our third-party midstream services revenues increased to $5.2 million , or an increase of almost three-fold, for +60 +Table of Contents +the year ended December 31, 2016 , as compared to $1.9 million for the year ended December 31, 2015 . This increase was primarily attributable to a significant increase in third-party salt water disposal revenue to approximately $1.6 million for the year ended December 31, 2016 , as compared to $0.2 million for the year ended December 31, 2015 , due to increased salt water disposal at our facilities in the Wolf asset area in 2016. The remaining increase was primarily attributable to third-party natural gas gathering and processing fees of $3.6 million for the year ended December 31, 2016 , as compared to $1.7 million for the year ended December 31, 2015 , including natural gas processing at the Black River Processing Plant, which began operating in August 2016. +Realized gain on derivatives . Our realized net gain on derivatives was $9.3 million for the year ended December 31, 2016 , as compared to a realized net gain of $77.1 million for the year ended December 31, 2015 . We realized net gain s of $5.9 million and $3.4 million from our oil and natural gas derivative contracts, respectively, for the year ended December 31, 2016 resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. Our realized net gain on derivatives was $77.1 million for the year ended December 31, 2015 . We realized net gain s of $62.3 million , $12.7 million and $2.2 million from our oil, natural gas and natural gas liquid (“NGL”) derivative contracts, respectively, for the year ended December 31, 2015 resulting from oil and natural gas prices being below the floor prices of most of our oil and natural gas costless collar contracts and NGL prices being below the fixed prices of all of our swap contracts. We realized an average gain of approximately $2.29 per Bbl hedged on all of our open oil costless collar contracts during the year ended December 31, 2016 , as compared to an average gain of $22.89 per Bbl hedged for the year ended December 31, 2015 . Our oil volumes hedged for the year ended December 31, 2016 were also 6% lower as compared to the year ended December 31, 2015 . We realized an average gain of approximately $0.26 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2016 , as compared to an average gain of approximately $0.73 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2015 . Our total natural gas volumes hedged for the year ended December 31, 2016 were also 23% lower than the total natural gas volumes hedged for the year ended December 31, 2015 . +Unrealized gain (loss) on derivatives. Our unrealized net loss on derivatives was $41.2 million for the year ended December 31, 2016 , as compared to an unrealized net loss of $39.3 million for the year ended December 31, 2015 . During the year ended December 31, 2016 , the net fair value of our open oil and natural gas derivatives contracts decrease d to a net liability of approximately $25.0 million from a net asset of $16.3 million for the year ended December 31, 2015 , resulting in an unrealized net loss on derivatives of $41.2 million for the year ended December 31, 2016 . During the year ended December 31, 2016 , the net fair value of our open oil and natural gas derivative contracts decrease d $32.2 million and $9.1 million , respectively, due to the increase in the underlying oil and natural gas futures prices at December 31, 2016, as well as realized gains from oil and natural gas derivative contracts settled during the year ended December 31, 2016 . +Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014 +Oil and natural gas revenues . Our oil and natural gas revenues decreased $89.4 million to $278.3 million, or a decrease of 24%, for the year ended December 31, 2015, as compared to $367.7 million for the year ended December 31, 2014. Our oil revenues decreased $86.7 million, a decrease of 30%, to $203.4 million for the year ended December 31, 2015, as compared to $290.0 million for the year ended December 31, 2014. The decrease in oil revenues resulted from a significantly lower weighted average oil price realized for the year ended December 31, 2015 of $45.27 per Bbl, as compared to $87.37 per Bbl realized for the year ended December 31, 2014. The lower weighted average oil price was partially mitigated by the 35% increase in our oil production to 4.5 million Bbl of oil for the year ended December 31, 2015, or about 12,306 Bbl of oil per day, as compared to just over 3.3 million Bbl of oil, or about 9,095 Bbl of oil per day, for the year ended December 31, 2014. This increased oil production was primarily a result of newly drilled and completed wells in the Delaware Basin, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our natural gas revenues decreased $2.7 million, or a decrease of 3%, to $75.0 million for the year ended December 31, 2015, as compared to $77.7 million for the year ended December 31, 2014. The decrease in natural gas revenues resulted from a lower weighted average natural gas price realized for the year ended December 31, 2015 of $2.71 per Mcf, as compared to $5.08 per Mcf realized for the year ended December 31, 2014. The lower weighted average natural gas price was partially mitigated by the 81% increase in our natural gas production to 27.7 Bcf for the year ended December 31, 2015, as compared to 15.3 Bcf for the year ended December 31, 2014. The increased natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, but also included increased natural gas production associated with our operations in the Delaware Basin and the Eagle Ford shale. +Third-party midstream services revenues. Our third-party midstream services revenues increased to $1.9 million , or an increase of 54% , for the year ended December 31, 2015 , as compared to $1.2 million for the December 31, 2014 . The increase was primarily attributable to third-party oil, natural gas and salt water gathering and salt water disposal fees in our Wolf asset area. +61 +Table of Contents +Realized gain (loss) on derivatives . Our realized net gain on derivatives was $77.1 million for the year ended December 31, 2015, as compared to a realized net gain of $5.0 million for the year ended December 31, 2014. We realized net gains of $62.3 million, $12.7 million and $2.2 million from our oil, natural gas and NGL derivative contracts, respectively, for the year ended December 31, 2015 resulting from oil and natural gas prices being below the floor prices of most of our costless collar contracts and NGL prices being below the fixed prices of all of our swap contracts. Our realized net gain on derivatives was $5.0 million for the year ended December 31, 2014. We realized a net gain from our oil derivative contracts of approximately $5.2 million and a net gain of $0.5 million from our NGL derivative contracts for the year ended December 31, 2014 due to oil prices being below the floor prices of some of our oil costless collar contracts and NGL prices being below the fixed prices of some of our swap contracts, respectively, especially during the latter part of 2014. These gains were partially offset by a net loss of $0.7 million on our natural gas derivative contracts, due to natural gas prices being in excess of the ceiling prices of our natural gas costless collar contracts, especially in the early months of 2014. We realized an average gain of approximately $22.89 per Bbl hedged on all of our open oil costless collar contracts during the year ended December 31, 2015, as compared to an average gain of $2.00 per Bbl hedged for the year ended December 31, 2014. Our oil volumes hedged for the year ended December 31, 2015 were also 5% higher as compared to the year ended December 31, 2014. We realized an average gain of approximately $0.73 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2015, as compared to an average loss of approximately $0.06 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2014. Our total natural gas volumes hedged for the year ended December 31, 2015 were also 38% higher than the total natural gas volumes hedged for the year ended December 31, 2014. +Unrealized gain (loss) on derivatives. Our unrealized net loss on derivatives was approximately $39.3 million for the year ended December 31, 2015, as compared to an unrealized net gain of approximately $58.3 million for the year ended December 31, 2014. During the year ended December 31, 2015, the net fair value of our open oil, natural gas and NGL derivatives contracts decreased to approximately $16.3 million from $55.5 million for the year ended December 31, 2014, resulting in an unrealized net loss on derivatives of approximately $39.3 million for the year ended December 31, 2015. During the year ended December 31, 2015, the net fair value of our open oil, natural gas and NGL derivative contracts decreased by $31.9 million, $5.4 million and $1.9 million, respectively, due primarily to the realized gains from oil, natural gas and NGL derivative contracts settled during the year ended December 31, 2015. +62 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2016 +2015 +2014 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing (1) +$ +43,046 +$ +35,650 +$ +33,172 +Lease operating (2) +56,202 +54,704 +49,945 +Plant and other midstream services operating +5,389 +3,489 +1,408 +Depletion, depreciation and amortization +122,048 +178,847 +134,737 +Accretion of asset retirement obligations +1,182 +734 +504 +Full-cost ceiling impairment +158,633 +801,166 +— +General and administrative +55,089 +50,105 +32,152 +Total expenses +441,589 +1,124,695 +251,918 +Operating (loss) income +(177,167 +) +(806,662 +) +180,331 +Other income (expense): +Net gain on asset sales and inventory impairment +107,277 +908 +— +Interest expense +(28,199 +) +(21,754 +) +(5,334 +) +Other (expense) income (3) +(4 +) +616 +132 +Total other income (expense) +79,074 +(20,230 +) +(5,202 +) +(Loss) income before income taxes +(98,093 +) +(826,892 +) +175,129 +Total income tax (benefit) provision +(1,036 +) +(147,368 +) +64,375 +Net (income) loss attributable to non-controlling interest in subsidiaries +(364 +) +(261 +) +17 +Net (loss) income attributable to Matador Resources Company shareholders +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +Expenses per BOE: +Production taxes, transportation and processing (1) +$ +4.23 +$ +3.91 +$ +5.65 +Lease operating (2) +$ +5.52 +$ +6.01 +$ +8.51 +Plant and other midstream services operating +$ +0.53 +$ +0.38 +$ +0.24 +Depletion, depreciation and amortization +$ +11.99 +$ +19.63 +$ +22.95 +General and administrative +$ +5.41 +$ +5.50 +$ +5.48 +________________ +(1) +$0.1 million, or $0.01 per BOE, was reclassified to third-party midstream revenues for the year ended December 31, 2015, due to our midstream business becoming a reportable segment in the third quarter of 2016. There was no such reclassification made in 2014. +(2) +$3.5 million, or $0.38 per BOE, and $1.4 million, or $0.24 per BOE, were reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016. +(3) +$1.7 million and $1.2 million were reclassified to midstream services revenues for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016. +Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015 +Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increase d $7.4 million to $43.0 million , an increase of 21% , for the year ended December 31, 2016 , as compared to $35.7 million for the year ended December 31, 2015 . On a unit-of-production basis, our production taxes, transportation and processing expenses increase d 8% to $4.23 per BOE for the year ended December 31, 2016 , as compared to $3.91 per BOE for the year ended December 31, 2015 . The increase in production taxes, transportation and processing expenses was primarily attributable to higher transportation and processing expenses of $26.5 million for the year ended December 31, 2016 , as compared to transportation and processing expenses of $22.4 million for the year ended December 31, 2015 . This increase of $4.1 million was primarily due to the increase in natural gas production in the Delaware Basin as a percentage of our total natural gas production for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 . Natural gas transportation and processing expenses are higher in the Delaware Basin, as compared to the Eagle Ford shale, as the natural gas gathering and processing infrastructure has yet to meet the demand for these services due to the increased drilling activity in the Delaware Basin over the last few years. We have begun to incur lower processing expenses for most of the natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico due to the start up in late August 2016 of the Black River Processing Plant, and we expect to fully realize the impact of these lower processing expenses once the plant is operational for an entire year. +63 +Table of Contents +Our production taxes increase d $3.4 million to $16.6 million for the year ended December 31, 2016 , as compared to $13.2 million for the year ended December 31, 2015 , primarily due to the 5% increase in oil and natural gas revenues for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 . In addition to the increase in production taxes attributable to the 5% increase in oil and natural gas revenues, the production tax rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production shifts from Texas to New Mexico, we expect to continue to experience increased production tax expenses. +Lease operating expenses. Our lease operating expenses increase d $1.5 million to $56.2 million , an increase of 3% , for the year ended December 31, 2016 , as compared to $54.7 million for the year ended December 31, 2015 . Our lease operating expenses per unit of production decrease d 8% to $5.52 per BOE for the year ended December 31, 2016 , as compared to $6.01 per BOE for the year ended December 31, 2015 . Our total oil and natural gas production increase d 12% to approximately 10.2 million BOE for the year ended December 31, 2016 from approximately 9.1 million BOE for the year ended December 31, 2015 . The decrease achieved in lease operating expenses on a unit-of-production basis was primarily attributable to several key factors, including (i) decreased field supervisory costs as a number of third-party contractors became full-time employees during the second quarter of 2016, (ii) decreased costs associated with our Eagle Ford operations, including supervisory, salt water disposal and chemical costs and (iii) increased oil equivalent production as compared to the year ended December 31, 2015 . This decrease was partially offset by (x) increased salt water disposal costs attributable to increased operations in the Rustler Breaks asset area and (y) increased workover expenses in the Wolf asset area. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increase d $1.9 million to $5.4 million , an increase of 54% , for the year ended December 31, 2016 , as compared to $3.5 million for the year ended December 31, 2015 . This increase was primarily attributable to the expenses associated with our salt water disposal operations of $3.6 million for the year ended December 31, 2016 , as compared to $2.2 million for the year ended December 31, 2015 . The remaining increase was primarily attributable to expenses associated with the Black River Processing Plant that began operating in August 2016. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decrease d $56.8 million to $122.0 million , a decrease of 32% , for the year ended December 31, 2016 , as compared to $178.8 million for the year ended December 31, 2015 . On a unit-of-production basis, our depletion, depreciation and amortization expenses decrease d 39% to $11.99 per BOE for the year ended December 31, 2016 , as compared to $19.63 per BOE for the year ended December 31, 2015 . The decrease in our total depletion, depreciation and amortization expenses resulted primarily from (i) higher total proved reserves of 105.8 million BOE, or an increase of 24% , at December 31, 2016, as compared to total proved reserves of 85.1 million BOE at December 31, 2015, (ii) the decreased cost on a unit-of-production basis associated with wells drilled in 2016, as compared to prior periods and (iii) the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2015 and 2016. This increase in total proved oil and natural gas reserves was primarily attributable to the continued delineation and development of our acreage in the Delaware Basin. +Full-cost ceiling impairment. Due primarily to the continued decline in oil and natural gas prices during the first half of 2016, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling. As a result, we recorded an impairment charge of $158.6 million , exclusive of tax effect, for the year ended December 31, 2016 to our net capitalized costs. This charge is reflected in our statement of operations for the year ended December 31, 2016, with the related deferred income tax credit recorded net of a valuation allowance. These full-cost impairment charges for the year ended December 31, 2016 were realized in the first two quarters of the year. Since that time, oil and natural gas prices have improved and as a result, no full-cost ceiling impairment charges were recorded in the third and fourth quarters of 2016. +Due primarily to the sharp decline in oil and natural gas prices during 2015, at December 31, 2015, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling. As a result, we recorded an impairment charge of $801.2 million , exclusive of tax effect, to our net capitalized costs. This charge is reflected in our statement of operations for the year ended December 31, 2015, with the related deferred income tax credit recorded net of a valuation allowance. +General and administrative. Our general and administrative expenses increase d $5.0 million to $55.1 million , an increase of 10% , for the year ended December 31, 2016 , as compared to $50.1 million for the year ended December 31, 2015 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses associated with additional employees joining the Company during the year ended December 31, 2016 to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of the continued growth of the Company. The remaining increase is largely due to a $2.9 million increase in non-cash stock-based compensation expense to $12.4 million for the year ended December 31, 2016 , as compared to $9.5 million for the year ended December 31, 2015 . The increase in our non-cash stock-based compensation expense was attributable to the increase d expense related to the continued vesting of awards granted from 2012 through 2016. Our general and administrative expenses decrease d 2% on a unit- +64 +Table of Contents +of-production basis to $5.41 per BOE for the year ended December 31, 2016 , as compared to $5.50 per BOE for the year ended December 31, 2015 . +Net gain on asset sales and inventory impairment. We recorded a net gain of $107.3 million on asset sales and inventory impairment for the year ended December 31, 2016, as compared to $0.9 million for the year ended December 31, 2015. On October 1, 2015, we completed the sale of our wholly-owned subsidiary that owned the Loving County Processing System to EnLink. The Loving County Processing System included the Wolf Processing Plant and approximately six miles of high pressure gathering pipeline that connects our natural gas gathering system to the Wolf Processing Plant. +Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and we received net proceeds of approximately $139.8 million, after deducting customary purchase price adjustments of approximately $3.6 million. Due to the terms of the Wolf Gathering Agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as a deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and processing agreement. See Note 13 to the consolidated financial statements in this Annual Report for more information on this agreement. +During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of the new plant, EnLink began processing our natural gas at the new plant. As such, the gathering and processing agreement is no longer considered a lease, and accordingly the Company recognized the remaining unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016 . +Interest expense. For the year ended December 31, 2016 , we incurred total interest expense of approximately $31.9 million . We capitalized approximately $3.7 million of our interest expense on certain qualifying projects for the year ended December 31, 2016 and expensed the remaining $28.2 million to operations. For the year ended December 31, 2015 , we incurred total interest expense of approximately $25.7 million . We capitalized approximately $3.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2015 and expensed the remaining $21.8 million to operations. The increase in total interest expense of $6.2 million for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 , was attributable to an increase in both the average debt outstanding and the coupon rate of 6.875% for the senior notes issued in 2015 and late 2016, as compared to the lower effective interest rates incurred on borrowings under our Credit Agreement. In December 2016, we used a portion of the net proceeds from the December 2016 senior notes and equity offerings to repay a total of $120.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2016 , we had no outstanding borrowings under our Credit Agreement, $0.8 million in outstanding letters of credit and $575.0 million in outstanding senior notes. Due to the higher coupon rate on the senior notes as compared to the interest rates under the Credit Agreement, we expect to incur increased interest expense in future periods. +Total income tax (benefit) provision . Our deferred tax assets exceeded our deferred tax liabilities at December 31, 2016 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in 2016 and 2015. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015. We retained a full valuation allowance at December 31, 2016 due to uncertainties regarding the future realization of our deferred tax assets. The current tax benefit of $1.0 million for the year ended December 31, 2016 was primarily attributable to a refund due from the Internal Revenue Service. The total income tax expense for the year ended December 31, 2016 differed from amounts computed by applying the U.S. federal statutory tax rate to the pre-tax loss due primarily to the recording of a valuation allowance against the net deferred tax asset position as a result of the full-cost ceiling impairments recorded for the years ended December 31, 2016 and 2015. +Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014 +Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased by $2.5 million to $35.7 million , an increase of 7%, for the year ended December 31, 2015, as compared to $33.2 million for the year ended December 31, 2014. On a unit-of-production basis, however, our production taxes and marketing expenses decreased by 31% to $3.91 per BOE for the year ended December 31, 2015, as compared to $5.65 per BOE for the year ended December 31, 2014. The increase in production taxes, transportation and processing expenses on an absolute basis was primarily attributable to higher natural gas transportation and processing expenses of $22.4 million for the year ended December 31, 2015, as compared to natural gas transportation and processing expenses of $15.2 million for the year ended December 31, 2014, an increase of $7.2 million, due to the 81% increase in our natural gas production to 27.7 Bcf for the year ended December 31, 2015, as compared to 15.3 Bcf of natural gas production for the year ended December 31, 2014. This increase was partially offset by a decrease in our production taxes of $4.8 million to $13.2 million for the year ended December +65 +Table of Contents +31, 2015, as compared to $18.0 million for the year ended December 31, 2014, primarily due to the 30% decrease in oil revenues for the year ended December 31, 2015, as compared to the year ended December 31, 2014. +Lease operating expenses. Our lease operating expenses increased by $4.8 million to $54.7 million, an increase of 10%, for the year ended December 31, 2015, as compared to $49.9 million for the year ended December 31, 2014. Our lease operating expenses per unit of production decreased 29% to $6.01 per BOE for the year ended December 31, 2015, as compared to $8.51 per BOE for the year ended December 31, 2014. Our total oil and natural gas production increased 55% to approximately 9.1 million BOE for the year ended December 31, 2015 from approximately 5.9 million BOE for the year ended December 31, 2014, including an increase of 35% in oil production to approximately 4.5 million Bbl for the year ended December 31, 2015, as compared to just over 3.3 million Bbl for the year ended December 31, 2014, which would typically result in higher lease operating expenses. Oil production was 49% of total production by volume for the year ended December 31, 2015, as compared to 57% of total production by volume for the year ended December 31, 2014. The decrease achieved in lease operating expenses on a unit-of-production basis was primarily attributable to several key factors, including (i) no clean-out operations on offsetting producing wells as a result of fracturing operations on newly drilled Eagle Ford shale wells as compared to the same period in 2014, (ii) a decrease in salt water disposal costs on a per barrel basis, particularly in the Delaware Basin, (iii) reduced service costs impacting lease operating expenses and (iv) a higher percentage of natural gas production, including a significant increase in Haynesville natural gas production, which typically has lower operating costs due to its lack of associated oil and water production. A joint venture controlled by us drilled, completed and began injecting salt water into a new disposal well in the Wolf asset area in Loving County, Texas in January 2015, which reduced salt water disposal costs in this area. A second salt water disposal well was drilled and tested in the Wolf asset area and began disposing of salt water in the fourth quarter of 2015. At December 31, 2015, this well was operating with temporary facilities, but it became fully operational with permanent facilities in the first quarter of 2016. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increase d by $2.1 million to $3.5 million , an increase of 148% , for the year ended December 31, 2015 , as compared to $1.4 million for the year ended December 31, 2014 . This increase was primarily attributable to the expenses associated with our salt water disposal facilities in our Wolf asset area, which began operations in early 2015. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $44.1 million to $178.8 million, an increase of 33%, for the year ended December 31, 2015, as compared to $134.7 million for the year ended December 31, 2014. On a unit-of-production basis, however, our depletion, depreciation and amortization expenses decreased 15% to $19.63 per BOE for the year ended December 31, 2015, as compared to $22.95 per BOE for the year ended December 31, 2014. The absolute increase in our depletion, depreciation and amortization expenses reflected an increase of 55% in our total oil and natural gas production to 9.1 million BOE for the year ended December 31, 2015 from 5.9 million BOE for the year ended December 31, 2014. The 15% decrease in the per-unit-of-production depletion, depreciation and amortization expenses resulted from the 24% increase in total proved oil and natural gas reserves from 68.7 million BOE at December 31, 2014 to 85.1 million BOE at December 31, 2015, which reserves were added at a lower cost per BOE, as well as from the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2015. +Full-cost ceiling impairment. Due primarily to the sharp decline in oil and natural gas prices during 2015, at December 31, 2015, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling. As a result, we recorded an impairment charge of $801.2 million, exclusive of tax effect, to our net capitalized costs. This charge is reflected in our statement of operations for the year ended December 31, 2015, with the related deferred income tax credit recorded net of a valuation allowance. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the year ended December 31, 2014. +General and administrative. Our general and administrative expenses increased by $18.0 million to $50.1 million, an increase of 56%, for the year ended December 31, 2015, as compared to $32.2 million for the year ended December 31, 2014. The increase in our general and administrative expenses was primarily attributable to increased payroll expenses associated with additional personnel joining the Company during the year ended December 31, 2015 to support our increased land, geoscience, drilling, completion, production, accounting and administration functions, including the addition of 29 new employees in Roswell, New Mexico as a result of the HEYCO Merger in late February 2015. The remaining increase is largely due to a $4.0 million increase in non-cash stock-based compensation expense to $9.5 million for the year ended December 31, 2015, as compared to $5.5 million for the year ended December 31, 2014. The increase in our non-cash stock-based compensation expense was attributable to the increased expense related to the continued vesting of awards granted from 2012 through 2015 of $9.5 million for the year ended December 31, 2015, as compared to $5.3 million for the year ended December 31, 2014. This increase was partially offset by the decreased expense related to our liability-based stock options of $0.1 million for the year ended December 31, 2015, as compared to $0.2 million for the year ended December 31, 2014. This decreased expense related to our liability-based stock options was attributable to the slight decrease in our stock price from $20.23 per +66 +Table of Contents +share at December 31, 2014 to $19.77 per share at December 31, 2015. Our general and administrative expenses increased by less than 1% on a unit-of-production basis to $5.50 per BOE for the year ended December 31, 2015, as compared to $5.48 per BOE for the year ended December 31, 2014. +Interest expense. For the year ended December 31, 2015, we incurred total interest expense of approximately $25.7 million. We capitalized approximately $3.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2015 and expensed the remaining $21.8 million to operations. For the year ended December 31, 2014, we incurred total interest expense of approximately $8.2 million. We capitalized approximately $2.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2014 and expensed the remaining $5.3 million to operations. The increase in total interest expense of $17.5 million for the year ended December 31, 2015, as compared to the year ended December 31, 2014, was attributable to an increase in both the average debt outstanding and the interest rate of 6.875% under the senior notes in 2015, as compared to the effective interest rate of approximately 3.3% under our Credit Agreement in 2014. In late April 2015, we used a portion of the net proceeds from the April 2015 senior notes and equity offerings to repay a total of $465.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2015, we had no outstanding borrowings under our Credit Agreement, $0.6 million in outstanding letters of credit and $400.0 million in outstanding senior notes. +Total income tax (benefit) provision . At December 31, 2015, our deferred tax assets exceeded our deferred tax liabilities and, as a result, we recorded a valuation allowance of $154.3 million against the deferred tax assets. The total income tax expense for the year ended December 31, 2015 differed from amounts computed by applying the U.S. federal statutory tax rates to the pre-tax loss due primarily to the recording of a valuation allowance against the net deferred tax asset position as a result of the full-cost ceiling impairment recorded for the year ended December 31, 2015. We recorded a total income tax benefit of $147.4 million for the year ended December 31, 2015. The total income tax benefit of $147.4 million for the year ended December 31, 2015 is comprised of a current tax expense of $3.0 million, which represented our estimated alternative minimum tax (“AMT”) liability, and a deferred tax benefit of $150.3 million. For the year ended December 31, 2014, we incurred an estimated AMT liability of $0.1 million, which represented the current portion of the income tax provision. The remaining income tax provision of $64.2 million represented deferred taxes for the year ended December 31, 2014. Our effective tax rate for the year ended December 31, 2014 was 36.8%. Total income tax expense for the year ended December 31, 2014 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily due to the impact of permanent differences between book and taxable income. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2017 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditure requirements through 2017 through a combination of cash on hand, operating cash flows, proceeds we received in connection with the formation of the Joint Venture and borrowings under our Credit Agreement (assuming availability under our borrowing base). We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows. +At December 31, 2016 , we had cash totaling approximately $212.9 million and restricted cash totaling approximately $1.3 million . Restricted cash represents cash held by our less-than-wholly-owned subsidiaries. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +On October 31, 2016 , the lenders party to our Credit Agreement increased our borrowing base from $300.0 million to $400.0 million . At December 31, 2016 and February 22, 2017 , the borrowing base under our Credit Agreement remained $400.0 million . At both dates, we had no outstanding borrowings and approximately $0.8 million in outstanding letters of credit under the Credit Agreement, and we had $575.0 million of outstanding senior notes. +On March 11, 2016, we completed a public offering of 7,500,000 shares of common stock (the “March Equity Offering”). After deducting offering costs totaling approximately $0.8 million , we received net proceeds of approximately $141.5 million . We used the net proceeds for general corporate purposes, including to fund a portion of our capital expenditures. +On December 9, 2016, we completed a public offering of 6,000,000 shares of common stock (the “December Equity Offering” and, together with the March Equity Offering, the “2016 Equity Offerings”). After deducting offering costs totaling approximately $0.4 million , we received net proceeds of approximately $145.8 million . +67 +Table of Contents +On December 9, 2016, we issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to the same indenture governing the Company’s original senior notes issued in April 2015 and were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5% . We received net proceeds from the Notes Offering of approximately $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. The Additional Notes are our senior unsecured obligations. The Additional Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year. +We have used a portion of the net proceeds from the Notes Offering and the December Equity Offering to fund the aggregate purchase price for certain leasehold and mineral acquisitions (some of which closed in January and February 2017) and further development of our midstream assets, to repay $120.0 million in outstanding borrowings under our Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig. +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the next five years. We continue to operate the Delaware Midstream Assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will continue to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2017 . We plan to operate four contracted drilling rigs in the Delaware Basin during the first quarter of 2017 and expect to add a fifth drilling rig in the Delaware Basin in the second quarter of 2017 . Our 2017 estimated capital expenditure budget consists of $370 to $390 million for drilling, completions, facilities and infrastructure and $56 to $64 million for midstream capital expenditures, which represents our 51% share of an estimated 2017 capital expenditure budget of $110 to $125 million for San Mateo. Substantially all of our 2017 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2017 Delaware Basin drilling program will focus on the continued development of the Wolf and Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested zones in the Wolf and Rustler Breaks asset areas during 2017. +We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2017. These expenditures are opportunity-specific and per-acre prices can vary significantly based on the prospect. As a result, it is difficult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2017. +From January 1 through February 22, 2017, we acquired approximately 13,900 gross ( 8,200 net) leasehold and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around our existing acreage in the Delaware Basin. As noted above, some of this acreage and a portion of the production included properties identified at the time of the Notes Offering and the December Equity Offering. These transactions were pending at the time of those offerings and closed subsequent to December 31, 2016, bringing our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres, almost all of which was located in the Delaware Basin. We have incurred capital expenditures of approximately $111 million since January 1, 2017 to acquire leasehold and mineral interests and the related production. +Our 2017 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, including the expansion of the Black River Processing Plant, the ability of our Joint Venture partner to meet its capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +68 +Table of Contents +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2017 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2017 and the hedges we currently have in place. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. As of February 22, 2017 , we had approximately 70% of our anticipated oil production and approximately 50% of our anticipated natural gas production hedged for 2017 . We have no hedges in place for natural gas liquids and no hedges in place for natural gas beyond 2017; however, we have a portion of our anticipated oil production volumes hedged in 2018. See Note 8 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2016 . See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” +Our cash flows for the years ended December 31, 2016, 2015 and 2014 are presented below. +Year Ended December 31, +2016 +2015 +2014 +(In thousands) +Net cash provided by operating activities +$ +134,086 +$ +208,535 +$ +251,481 +Net cash used in investing activities +(405,640 +) +(425,154 +) +(570,531 +) +Net cash provided by financing activities +467,706 +224,944 +321,170 +Net change in cash +$ +196,152 +$ +8,325 +$ +2,120 +Cash Flows Provided by Operating Activities +Net cash provided by operating activities decreased $74.4 million to $134.1 million for the year ended December 31, 2016 , as compared to net cash provided by operating activities of $208.5 million for the year ended December 31, 2015 . Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $132.3 million for the year ended December 31, 2016 from $199.6 million for the year ended December 31, 2015 . This decrease was primarily attributable to the decrease in our realized gain on derivatives, which declined by $67.8 million to $9.3 million for the year ended December 31, 2016 , as compared to $77.1 million for the year ended December 31, 2015 . Changes in our operating assets and liabilities between December 31, 2015 and December 31, 2016 also resulted in a net decrease of approximately $7.2 million in net cash provided by operating activities for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 . +Net cash provided by operating activities decreased by $42.9 million to $208.5 million for the year ended December 31, 2015 , as compared to net cash provided by operating activities of $251.5 million for the year ended December 31, 2014 . Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $199.6 million for the year ended December 31, 2015 from $257.5 million for the year ended December 31, 2014 . This decrease was primarily attributable to the decrease in oil revenues from 2014 to 2015, resulting from a significantly lower weighted average oil price realized for the year ended December 31, 2015 of $45.27 per Bbl, as compared to $87.37 per Bbl realized for the year ended December 31, 2014 . This decrease was partially offset by the increase of 35% in our oil production to approximately 4.5 million Bbl from just over 3.3 million Bbl during the respective periods. Changes in our operating assets and liabilities between December 31, 2014 and December 31, 2015 also resulted in a net increase of approximately $15.0 million in net cash provided by operating activities for the year ended December 31, 2015 , as compared to the year ended December 31, 2014 . +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service +69 +Table of Contents +agreements in order to minimize ongoing future commitments. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities decreased $19.5 million to $405.6 million for the year ended December 31, 2016 from $425.2 million for the year ended December 31, 2015 . This decrease in net cash used in investing activities included (i) a decrease of $53.6 million in oil and natural gas properties capital expenditures for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 , (ii) an increase of approximately $10.3 million in expenditures for other property and equipment, which includes the construction of the Black River Processing Plant and new pipeline infrastructure, (iii) a decrease in cash used for acquisitions as the HEYCO Merger occurred in 2015, (iv) a reduction in proceeds from sales of assets as the sale of the Loving County Processing System to EnLink occurred in 2015 and (v) a decrease in our restricted cash of $43.7 million attributable to the release from escrow of potential like-kind-exchange funds in connection with the sale of the Loving County Processing System to EnLink. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2016 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition of additional acreage and mineral interests in the Delaware Basin. +Net cash used in investing activities decreased by $145.4 million to $425.2 million for the year ended December 31, 2015 from $570.5 million for the year ended December 31, 2014 . This decrease in net cash used in investing activities included (i) a decrease of $128.1 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2015 , as compared to the year ended December 31, 2014 , (ii) proceeds from the sale of the Loving County Processing System to EnLink of $139.8 million, (iii) an increase of approximately $55.3 million in expenditures for other property and equipment, which includes the Wolf Processing Plant and salt water disposal facilities we constructed in Loving County, Texas as well as initial costs associated with the Black River Processing Plant and new pipeline infrastructure, (iv) cash used in the HEYCO Merger of $24.0 million and (v) an increase in our restricted cash of $43.1 million attributable to the escrow account associated with potential like-kind-exchange transactions in connection with the sale of the Loving County Processing System to EnLink. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2015 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as to our operated and non-operated drilling activities in the Eagle Ford shale play and certain non-operated drilling activities in the Haynesville shale. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $467.7 million for the year ended December 31, 2016 , as compared to net cash provided by financing activities of $224.9 million for the year ended December 31, 2015 . The net cash provided by financing activities for the year ended December 31, 2016 was primarily attributable to the total proceeds of the 2016 Equity Offerings of $288.5 million , the total proceeds of the Notes Offering of $184.6 million and borrowings under our Credit Agreement of $120.0 million , offset by the costs of the 2016 Equity Offerings of $0.8 million , the costs of the Notes Offering of $2.7 million , the repayment of $120.0 million in borrowings under our Credit Agreement in December 2016 and the payment of $1.9 million in taxes related to net share settlement of stock-based compensation. +Net cash provided by financing activities was $224.9 million for the year ended December 31, 2015 , as compared to net cash provided by financing activities of $321.2 million for the year ended December 31, 2014 . The net cash provided by financing activities for the year ended December 31, 2015 was primarily attributable to the total proceeds of our April 2015 public equity offering of $188.7 million , total proceeds of our April 2015 notes offering of $400.0 million, borrowings under our Credit Agreement of $125.0 million and capital contributed from the non-controlling interest owners in our less-than-wholly-owned subsidiaries of $0.6 million, offset by the costs of the equity offering of $1.2 million , the costs of the April 2015 notes offering of $9.6 million, the repayment of $477.0 million in borrowings under our Credit Agreement during the period and the payment of $1.6 million in taxes related to net share settlement of stock-based compensation. +Net cash provided by financing activities was $321.2 million for the year ended December 31, 2014 . The net cash provided by financing activities for the year ended December 31, 2014 was primarily attributable to the total proceeds from our May 2014 public equity offering of $181.9 million and total borrowings of $320.0 million under our Credit Agreement during the period, offset by the costs of the offering of $0.6 million incurred during the period and by the repayment of $180.0 million in borrowings under our Credit Agreement during the period. +See Note 6 to the consolidated financial statements in this Annual Report for a summary of our debt, including our Credit Agreement and the senior notes. +70 +Table of Contents +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2016 , the material off-balance sheet arrangements and transactions that we had entered into include (i) operating lease agreements, (ii) non-operated drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) firm transportation, gathering, processing, disposal and fractionation commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 13 to the consolidated financial statements in this Annual Report for more information regarding the Company’s off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2016 . +Payments Due by Period +Total +Less Than 1 Year +1-3 Years +3-5 Years +More Than 5 Years +(In thousands) +Contractual Obligations: +Revolving credit borrowings, including letters of credit (1) +$ +821 +$ +— +$ +— +$ +821 +$ +— +Senior unsecured notes (2) +575,000 +— +— +— +575,000 +Office leases +25,063 +2,443 +5,023 +5,262 +12,335 +Non-operated drilling commitments (3) +11,053 +11,053 +— +— +— +Drilling rig contracts (4) +46,295 +26,017 +20,278 +— +— +Asset retirement obligations +20,641 +915 +982 +558 +18,186 +Natural gas processing and transportation agreements (5) +12,877 +10,599 +2,278 +— +— +Total contractual cash obligations +$ +691,750 +$ +51,027 +$ +28,561 +$ +6,641 +$ +605,521 +__________________ +(1) +At December 31, 2016 , we had no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020. +(2) +The amounts included in the table above represent principal maturities only. +(3) +At December 31, 2016 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2016 . If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $11.1 million at December 31, 2016 , which we expect to incur within the next year. +(4) +We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) +Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. Effective October 1, 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +71 +Table of Contents +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Prices for oil, natural gas and natural gas liquids affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +In 2016, oil and natural gas prices remained significantly below their most recent highs in 2014, although commodity prices did begin to improve in the latter half of 2016. Oil prices had increased to $54.06 per Bbl in late December 2016 from $37.04 on December 31, 2015, and natural gas prices had increased to $3.93 per MMBtu in late December 2016 from $2.34 per MMBtu on December 31, 2015. The sharp declines in oil and natural gas prices since late 2014 have impacted our revenues, profitability and cash flows in 2015 and 2016, as compared to 2014, and additional declines in oil and natural gas prices could have an adverse impact on our borrowing capacity, ability to obtain additional capital, revenues, profitability and cash flows. We are uncertain if oil and natural gas prices may continue to rise from their current levels, and in fact, oil and natural gas prices may decrease again in future periods. +For the year ended December 31, 2016 , oil prices averaged $43.40 per Bbl, ranging from a high of $54.06 per Bbl in late December to a low of $26.21 per Bbl in mid-February , based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $41.19 per Bbl ( $42.34 per Bbl including realized gains from oil derivatives) for our oil production for the year ended December 31, 2016 , as compared to $45.27 per Bbl ( $59.13 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2015 . At February 24, 2017 , the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had remained fairly steady, closing at $53.99 per Bbl, as compared to $32.15 per Bbl at February 24, 2016 . +For the year ended December 31, 2016 , natural gas prices averaged $2.55 per MMBtu, ranging from a high of approximately $3.93 per MMBtu in late December to a low of approximately $1.64 per MMBtu in early March , based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $2.66 per Mcf ( $2.78 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2016 , as compared to $2.71 per Mcf ( $3.24 per Mcf including realized gains from natural gas and NGL derivatives) for the year ended December 31, 2015 . At February 24, 2017 , the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had declined from late December, closing at $2.63 per MMBtu, as compared to $1.78 per MMBtu at February 24, 2016 . +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2017 . We plan to operate four contracted drilling rigs in the Delaware Basin during the first quarter of 2017 , with a fifth drilling rig added in the Delaware Basin in the second quarter of 2017 . Our 2017 estimated capital expenditure budget consists of $370 to $390 million for drilling, completions, facilities and infrastructure and $56 to $64 million for midstream capital expenditures, which represents our 51% share of an estimated 2017 capital expenditure budget of $110 to $125 million for San Mateo. Substantially all of our 2017 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2017 Delaware Basin drilling program will focus on the continued development of the Wolf and Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested zones in the Wolf and Rustler Breaks asset areas during 2017. +We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2017. These expenditures are opportunity-specific and per-acre prices can vary significantly based on the prospect. As a result, it is difficult +72 +Table of Contents +to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2017. +Coinciding with the recent improvements in oil and natural gas prices in late 2016, we have begun to experience price increases from our service providers for some of the products and services we use in our drilling, completion and production operations. If oil and natural gas prices remain at their current levels for a longer period of time or should they increase further, we would anticipate receiving additional price increases for drilling, completion and production products and services, although we can provide no assurances as to the eventual magnitude of these increases. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and natural gas liquids price declines, however, drilling additional oil or natural gas wells may not be economical, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2016 . Such information is incorporated herein by reference. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +73 +Table of Contents +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related reserves. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments typically consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized gain (loss) on derivatives.” Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under Revenues as “Realized gain (loss) on derivatives.” +Revenue Recognition +We follow the sales method of accounting for our oil, natural gas and natural gas liquids revenue, whereby we recognize revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural gas and natural gas liquids are produced and sold, and we accrue for revenue earned but not yet received. We recognize midstream services revenues at the time services have been rendered and the price is fixed and determinable. +74 +Table of Contents +Stock-Based Compensation +We account for stock-based compensation in accordance with ASC 718. Since 2012, all stock option awards have been granted under the 2012 Long-Term Incentive Plan or, for awards granted after June 10, 2015, under the Amended and Restated 2012 Long-Term Incentive Plan, and all of these awards were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these awards have been accounted for as liability instruments. We used the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, prior to the beginning of 2016, we estimated the future volatility of our stock using the historical volatility of the common stock of a group of companies we consider to be a representative peer group. Beginning in 2016, we began using our own historical volatility to estimate the future volatility of our stock as we had four years of historical stock prices as a publicly traded company. Management believes that, beginning in 2016, our own average historical volatility rates are the best available indicator of future volatility. +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the fair value of our stock on the date of the grant. See Note 8 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2016 . Such information is incorporated herein by reference. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural +75 +Table of Contents +gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” +Recent Accounting Pronouncements +See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and natural gas liquids fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2016 , Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and SunTrust Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2016 , we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any oil contract is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. +When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +See Note 11 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2016 . Such information is incorporated herein by reference. +Effect of Recent Derivatives Legislation. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain of these regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of +76 +Table of Contents +position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2016 we had no outstanding borrowings under our Credit Agreement and $575.0 million in senior notes outstanding at a coupon rate of 6.875% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our oil, natural gas and natural gas liquids derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 22, 2017 were Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and SunTrust Bank (or affiliates thereof), which are lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016, 2015 and 2014 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report. See the index to the financial statements in Item 15. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in +77 +Table of Contents +the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2016 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2016 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +78 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2016 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2016 , 2015 and 2014, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016 , and our report dated March 1, 2017 expressed an unqualified opinion on those consolidated financial statements. +/s/ KPMG LLP +Dallas, Texas +March 1, 2017 +79 +Table of Contents +Item 9B. Other Information. +Not applicable. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +80 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2016 and 2015 , Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 . +2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report. +81 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011). +2.2 +Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 20, 2015).* +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to our Annual Report on Form 10-K for the year ended December 31, 2014). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.4 to our Annual Report on Form 10-K for the year ended December 31, 2014). +2.5 +Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.5 to our Annual Report on Form 10-K for the year ended December 31, 2014).* +2.6 +Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on March 2, 2015).* +2.7 +Amendment No. 5 to Agreement and Plan of Merger, dated as of April 15, 2015, by and among HEYCO Energy Group, Inc., Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on April 15, 2015). +2.8 +Amendment No. 6 to Agreement and Plan of Merger, dated as of July 20, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.9 +Amendment No. 7 to Agreement and Plan of Merger, dated as of August 24, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.10 +Amendment No. 8 to Agreement and Plan of Merger, dated as of September 18, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.11 +Amendment No. 9 to Agreement and Plan of Merger, dated as of March 1, 2016, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016). +2.12 +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).* +3.1 +Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011). +3.2 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13, 2012). +82 +Table of Contents +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 23, 2016). +3.5 +Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on March 2, 2015). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 2, 2015). +4.3 +Voting Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on March 2, 2015). +4.4 +Indenture, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015). +4.5 +First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf Midstream, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 5, 2015). +4.6 +Second Supplemental Indenture, dated as of November 4, 2015, by and among Matador Resources Company, MRC Permian LKE Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +4.7 +Third Supplemental Indenture, dated as of June 8, 2016, by and among Matador Resources Company, Black River Water Management Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 14, 2016). +4.8 +Registration Rights Agreement, dated as of December 9, 2016, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on December 9, 2016). +4.9 +Fourth Supplemental Indenture, dated as of February 17, 2017, by and among Matador Resources Company, Black River Water Management Company, LLC, DLK Black River Midstream, LLC, Longwood Midstream Holdings, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 24, 2017). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +83 +Table of Contents +10.7† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.8† +First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.10† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.11† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.12† +Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.13† +Matador Resources Company Amended and Restated Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 14, 2016). +10.14† +Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.15† +First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.16† +Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.17† +Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.18† +Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.19† +Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.20† +Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.21† +Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). +10.22† +Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.23† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +10.24 +Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011 (incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). +84 +Table of Contents +10.25 +First Amendment to Purchase Sale and Participation Agreement, dated as of June 12, 2013, by and between MRC Energy Company and Orca/ICI Development (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.26† +Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.27† +Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.28† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.29† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.30† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.31† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.32† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.33† +Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.34† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.35† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.36† +Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.37 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.38 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.39 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.40 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +85 +Table of Contents +10.41 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.42 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.43 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.44 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.45 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.46 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.47 +Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016). +10.48 +Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016). +10.49† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.50† +Letter Agreement between Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., dated February 26, 2015 (incorporated by reference to Exhibit 10.51 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.51† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.52† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.53† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.55 to our Annual Report on Form 10-K for the year ended December 31, 2014). +10.54† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to our Annual Report on Form 10-K for the year ended December 31, 2015). +10.55† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2015). +10.56† +Amended and Restated Independent Contractor Agreement by and among Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., effective as of April 1, 2015 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 11, 2015). +86 +Table of Contents +10.57 +Purchase Agreement, dated as of April 9, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 14, 2015). +10.58† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.59† +Separation Agreement and Release, dated as of August 31, 2015, by and between Matador Resources Company and Ryan C. London (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q/A for the quarter ended September 30, 2015). +10.60† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to our Annual Report on Form 10-K for the year ended December 31, 2015). +10.61 +Purchase Agreement, dated as of December 6, 2016, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 9, 2016). +10.62† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (filed herewith). +10.63† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (filed herewith). +10.64† +Form of Letter Agreement between Matador Resources Company and certain directors modifying Restricted Stock Unit Award Agreements (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2016, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +† +Indicates a management contract or compensatory plan or arrangement. +* +Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +87 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +March 1, 2017 +By: +/s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +88 +Table of Contents +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Joseph Wm. Foran +Chairman and Chief Executive Officer +March 1, 2017 +Joseph Wm. Foran +(Principal Executive Officer) +/s/ David E. Lancaster +Executive Vice President and +Chief Financial Officer +March 1, 2017 +David E. Lancaster +(Principal Financial Officer) +/s/ Robert T. Macalik +Vice President and Chief Accounting +March 1, 2017 +Robert T. Macalik +Officer (Principal Accounting Officer) +/s/ Reynald A. Baribault +Director +March 1, 2017 +Reynald A. Baribault +/s/ R. Gaines Baty +Director +March 1, 2017 +R. Gaines Baty +/s/ Craig T. Burkert +Director +March 1, 2017 +Craig T. Burkert +/s/ William M. Byerley +Director +March 1, 2017 +William M. Byerley +/s/ Joe A. Davis +Director +March 1, 2017 +Joe A. Davis +/s/ Julia P. Forrester +Director +March 1, 2017 +Julia P. Forrester +/s/ David M. Laney +Director +March 1, 2017 +David M. Laney +/s/ Gregory E. Mitchell +Director +March 1, 2017 +Gregory E. Mitchell +/s/ Steven W. Ohnimus +Director +March 1, 2017 +Steven W. Ohnimus +/s/ Kenneth L. Stewart +Director +March 1, 2017 +Kenneth L. Stewart +/s/ George M. Yates +Director +March 1, 2017 +George M. Yates +89 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or other liquid hydrocarbons. +Bcf . One billion cubic feet. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +90 +Table of Contents +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil or other liquid hydrocarbons. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +91 +Table of Contents +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +92 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2016, 2015 and 2014 +Contents +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2016 and 2015 +F-3 +Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 +F-4 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014 +F-5 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 +F-6 +Notes to Consolidated Financial Statements +F-7 +Unaudited Supplementary Information +F-39 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (collectively the “Company”) as of December 31, 2016 and 2015 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2016 . These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Matador Resources Company and subsidiaries as of December 31, 2016 and 2015 , and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016 , in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016 , based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +/s/ KPMG LLP +Dallas, Texas +March 1, 2017 +F-2 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2016 +2015 +ASSETS +Current assets +Cash +$ +212,884 +$ +16,732 +Restricted cash +1,258 +44,357 +Accounts receivable +Oil and natural gas revenues +34,154 +16,616 +Joint interest billings +19,347 +16,999 +Other +5,167 +10,794 +Derivative instruments +— +16,284 +Lease and well equipment inventory +3,045 +2,022 +Prepaid expenses and other assets +3,327 +3,203 +Total current assets +279,182 +127,007 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +2,408,305 +2,122,174 +Unproved and unevaluated +479,736 +387,504 +Other property and equipment +160,795 +86,387 +Less accumulated depletion, depreciation and amortization +(1,864,311 +) +(1,583,659 +) +Net property and equipment +1,184,525 +1,012,406 +Other assets +958 +1,448 +Total assets +$ +1,464,665 +$ +1,140,861 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +4,674 +$ +10,966 +Accrued liabilities +101,460 +92,369 +Royalties payable +23,988 +16,493 +Amounts due to affiliates +8,651 +5,670 +Derivative instruments +24,203 +— +Advances from joint interest owners +1,700 +700 +Deferred gain on plant sale +— +4,830 +Amounts due to joint ventures +4,251 +2,793 +Income taxes payable +— +2,848 +Other current liabilities +578 +161 +Total current liabilities +169,505 +136,830 +Long-term liabilities +Senior unsecured notes payable +573,924 +391,254 +Asset retirement obligations +19,725 +15,166 +Derivative instruments +751 +— +Amounts due to joint ventures +1,771 +3,956 +Deferred gain on plant sale +— +102,506 +Other long-term liabilities +7,544 +2,190 +Total long-term liabilities +603,715 +515,072 +Commitments and contingencies (Note 13) +Shareholders’ equity +Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively +995 +856 +Additional paid-in capital +1,325,481 +1,026,077 +Accumulated deficit +(636,351 +) +(538,930 +) +Total Matador Resources Company shareholders’ equity +690,125 +488,003 +Non-controlling interest in subsidiaries +1,320 +956 +Total shareholders’ equity +691,445 +488,959 +Total liabilities and shareholders’ equity +$ +1,464,665 +$ +1,140,861 +The accompanying notes are an integral part of these financial statements. +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2016 +2015 +2014 +Revenues +Oil and natural gas revenues +$ +291,156 +$ +278,340 +$ +367,712 +Third-party midstream services revenues +5,218 +1,864 +1,213 +Realized gain on derivatives +9,286 +77,094 +5,022 +Unrealized (loss) gain on derivatives +(41,238 +) +(39,265 +) +58,302 +Total revenues +264,422 +318,033 +432,249 +Expenses +Production taxes, transportation and processing +43,046 +35,650 +33,172 +Lease operating +56,202 +54,704 +49,945 +Plant and other midstream services operating +5,389 +3,489 +1,408 +Depletion, depreciation and amortization +122,048 +178,847 +134,737 +Accretion of asset retirement obligations +1,182 +734 +504 +Full-cost ceiling impairment +158,633 +801,166 +— +General and administrative +55,089 +50,105 +32,152 +Total expenses +441,589 +1,124,695 +251,918 +Operating (loss) income +(177,167 +) +(806,662 +) +180,331 +Other income (expense) +Net gain on asset sales and inventory impairment +107,277 +908 +— +Interest expense +(28,199 +) +(21,754 +) +(5,334 +) +Other (expense) income +(4 +) +616 +132 +Total other income (expense) +79,074 +(20,230 +) +(5,202 +) +(Loss) income before income taxes +(98,093 +) +(826,892 +) +175,129 +Income tax provision (benefit) +Current +(1,036 +) +2,959 +133 +Deferred +— +(150,327 +) +64,242 +Total income tax (benefit) provision +(1,036 +) +(147,368 +) +64,375 +Net (loss) income +(97,057 +) +(679,524 +) +110,754 +Net (income) loss attributable to non-controlling interest in subsidiaries +(364 +) +(261 +) +17 +Net (loss) income attributable to +Matador Resources Company shareholders +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +Earnings (loss) per common share +Basic +$ +(1.07 +) +$ +(8.34 +) +$ +1.58 +Diluted +$ +(1.07 +) +$ +(8.34 +) +$ +1.56 +Weighted average common shares outstanding +Basic +91,273 +81,537 +70,229 +Diluted +91,273 +81,537 +70,906 +The accompanying notes are an integral part of these financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2016, 2015 and 2014 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital +Retained earnings (deficit ) +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders ’ equity +Common Stock +Preferred Stock +Shares +Amount +Shares +Amount +Shares +Amount +Balance at January 1, 2014 +66,959 +$ +670 +— +$ +— +$ +548,935 +$ +30,084 +1,306 +$ +(10,765 +) +$ +568,924 +$ +— +$ +568,924 +Issuance of common stock +7,500 +75 +— +— +181,800 +— +— +— +181,875 +— +181,875 +Cost to issue equity +— +— +— +— +(590 +) +— +— +— +(590 +) +— +(590 +) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +30 +— +— +— +16 +— +— +— +16 +— +16 +Stock options expense related to equity-based awards +— +— +— +— +2,279 +— +— +— +2,279 +— +2,279 +Stock options exercised, net of options forfeited in net share settlements +8 +— +— +— +43 +— +— +— +43 +— +43 +Liability-based stock option awards settled +— +— +— +— +84 +— +— +— +84 +— +84 +Restricted stock issued +212 +2 +— +— +(2 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +(17 +) +— +60 +— +(17 +) +— +(17 +) +Restricted stock and restricted stock units expense +— +— +— +— +3,023 +— +— +— +3,023 +— +3,023 +Cancellation of treasury stock +(1,335 +) +(13 +) +— +— +(10,752 +) +— +(1,335 +) +10,765 +— +— +— +Capital contributed to less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +150 +150 +Current period net income (loss) +— +— +— +— +— +110,771 +— +— +110,771 +(17 +) +110,754 +Balance at December 31, 2014 +73,374 +734 +— +— +724,819 +140,855 +31 +— +866,408 +133 +866,541 +Issuance of common stock +10,329 +104 +— +— +260,148 +— +— +— +260,252 +— +260,252 +Issuance of preferred stock +— +— +150 +1 +32,489 +— +— +— +32,490 +— +32,490 +Cost to issue equity +— +— +— +— +(1,151 +) +— +— +— +(1,151 +) +— +(1,151 +) +Conversion of preferred stock to common stock +1,500 +15 +(150 +) +(1 +) +(14 +) +— +— +— +— +— +— +Stock-based compensation expense related to equity-based awards +— +— +— +— +9,333 +— +— +— +9,333 +— +9,333 +Stock options exercised, net of options forfeited in net share settlements +25 +— +— +— +10 +— +— +— +10 +— +10 +Liability-based stock option awards settled +25 +— +— +— +446 +— +— +— +446 +— +446 +Restricted stock issued +429 +4 +— +— +(4 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +— +— +138 +— +— +— +— +Vesting of restricted stock units +52 +1 +— +— +(1 +) +— +— +— +— +— +— +Cancellation of treasury stock +(167 +) +(2 +) +— +— +2 +— +(167 +) +— +— +— +— +Capital contributed from less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +562 +562 +Current period net (loss) income +— +— +— +— +— +(679,785 +) +— +— +(679,785 +) +261 +(679,524 +) +Balance at December 31, 2015 +85,567 +856 +— +— +1,026,077 +(538,930 +) +2 +— +488,003 +956 +488,959 +Issuance of common stock pursuant to public offerings +13,500 +135 +— +— +288,375 +— +— +— +288,510 +— +288,510 +Issuance of common stock pursuant to employee stock compensation plan +471 +4 +— +— +(4 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +51 +1 +— +— +(1 +) +— +— +— +— +— +— +Cost to issue equity +— +— +— +— +(1,190 +) +— +— +— +(1,190 +) +— +(1,190 +) +Stock-based compensation expense related to equity-based awards +— +— +— +— +11,958 +— +— +— +11,958 +— +11,958 +Stock options exercised, net of options forfeited in net share settlements +36 +— +— +— +10 +— +— +— +10 +— +10 +Liability-based stock option awards settled +10 +— +— +— +255 +— +— +— +255 +— +255 +Restricted stock forfeited +— +— +— +— +— +— +120 +— +— +— +— +Cancellation of treasury stock +(116 +) +(1 +) +— +— +1 +— +(116 +) +— +— +— +— +Current period net (loss) income +— +— +— +— +— +(97,421 +) +— +— +(97,421 +) +364 +(97,057 +) +Balance at December 31, 2016 +99,519 +$ +995 +— +$ +— +$ +1,325,481 +$ +(636,351 +) +6 +$ +— +$ +690,125 +$ +1,320 +$ +691,445 +The accompanying notes are an integral part of these financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +2016 +2015 +2014 +Operating activities +Net (loss) income +$ +(97,057 +) +$ +(679,524 +) +$ +110,754 +Adjustments to reconcile net (loss) income to net cash provided by operating activities +Unrealized loss (gain) on derivatives +41,238 +39,265 +(58,302 +) +Depletion, depreciation and amortization +122,048 +178,847 +134,737 +Accretion of asset retirement obligations +1,182 +734 +504 +Full-cost ceiling impairment +158,633 +801,166 +— +Stock-based compensation expense +12,362 +9,450 +5,524 +Deferred income tax (benefit) provision +— +(150,327 +) +64,242 +Amortization of debt issuance cost +1,148 +852 +— +Net gain on asset sales and inventory impairment +(107,277 +) +(908 +) +— +Changes in operating assets and liabilities +Accounts receivable +(14,259 +) +3,633 +(13,318 +) +Lease and well equipment inventory +(700 +) +(180 +) +(211 +) +Prepaid expenses +(124 +) +(544 +) +(783 +) +Other assets +490 +(552 +) +1,212 +Accounts payable, accrued liabilities and other current liabilities +6,611 +1,375 +607 +Royalties payable +7,495 +1,654 +6,663 +Advances from joint interest owners +1,000 +700 +— +Income taxes payable +(2,848 +) +2,405 +39 +Other long-term liabilities +4,144 +489 +(187 +) +Net cash provided by operating activities +134,086 +208,535 +251,481 +Investing activities +Proceeds from sale of assets +5,173 +139,836 +79 +Oil and natural gas properties capital expenditures +(379,067 +) +(432,715 +) +(560,849 +) +Expenditures for other property and equipment +(74,845 +) +(64,499 +) +(9,152 +) +Business combination, net of cash acquired +— +(24,028 +) +— +Restricted cash +43,098 +(43,098 +) +— +Restricted cash in less-than-wholly-owned subsidiaries +1 +(650 +) +(609 +) +Net cash used in investing activities +(405,640 +) +(425,154 +) +(570,531 +) +Financing activities +Repayments of borrowings +(120,000 +) +(476,982 +) +(180,000 +) +Borrowings under Credit Agreement +120,000 +125,000 +320,000 +Proceeds from issuance of common stock +288,510 +188,720 +181,875 +Proceeds from issuance of senior unsecured notes +184,625 +400,000 +— +Cost to issue equity +(847 +) +(1,158 +) +(590 +) +Cost to issue senior unsecured notes +(2,734 +) +(9,598 +) +— +Proceeds from stock options exercised +100 +10 +43 +Capital commitments from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +562 +150 +Taxes paid related to net share settlement of stock-based compensation +(1,948 +) +(1,610 +) +(308 +) +Net cash provided by financing activities +467,706 +224,944 +321,170 +Increase in cash +196,152 +8,325 +2,120 +Cash at beginning of year +16,732 +8,407 +6,287 +Cash at end of year +$ +212,884 +$ +16,732 +$ +8,407 +Supplemental disclosures of cash flow information (Note 14) +The accompanying notes are an integral part of these financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2016, 2015 and 2014 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations in support of its exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Reclassifications +Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. As a result of the growth of the Company’s midstream operations, these operations met the required threshold for segment reporting at December 31, 2016 . As a result, $1.8 million and $1.2 million for the years ended December 31, 2015 and 2014 , respectively, were reclassified from other income to third-party midstream services revenues. In addition, $3.5 million and $1.4 million related to midstream operating costs for the years ended December 31, 2015 and 2014 , respectively, were reclassified from lease operating expenses to plant and other midstream services operating expenses. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. +Change in Accounting Principles +During the second quarter of 2016, the Company adopted Accounting Standards Update (“ASU”) 2016-09, Compensation - Stock Compensation (Topic 718) , which simplifies several aspects of the accounting for employee share-based payment transactions, including accounting for income tax, forfeitures, statutory tax withholding requirements, classifications of awards as either equity or liability and classification of taxes in the statement of cash flows, requiring either retrospective, modified retrospective or prospective transition. The amended guidance also requires an entity to record excess tax benefits and deficiencies in the income statement. The adoption of this ASU had no impact on any period presented for (i) the Company’s financial position or statements of operations, as the Company currently has a valuation allowance against its net deferred tax assets, or (ii) the Company’s statements of cash flows, as the Company has historically accounted for taxes paid for net share settlement as a financing activity as required under this ASU. In addition, the Company uses historical forfeiture rates to estimate future forfeitures attributable to the service-based vesting requirements not being met and has continued to do so upon adoption of this ASU. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Restricted Cash +Restricted cash represents a portion of the cash paid for the Loving County Processing System by EnLink (as described in Note 5) directly to a qualified intermediary to facilitate like-kind-exchange transactions for federal income tax purposes as well as cash held by the Company’s less-than-wholly-owned subsidiaries. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions and, in January 2016, the remaining balance of $42.1 million was returned to the Company by the qualified intermediary to be used for general corporate purposes. By contractual agreement, the cash in the account held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $15.7 million , $6.9 million and $6.4 million of its general and administrative costs in 2016 , 2015 and 2014 , respectively. The Company capitalized $3.7 million , $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016, 2015 and 2014 , respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million , exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). +During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million , exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). +During the year ended December 31, 2014, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2014. +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Other Property and Equipment +Other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of other property and equipment. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments. +Revenue Recognition +The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable. +For the year ended December 31, 2016 , three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. ( 18% ), Shell Trading (US) Company ( 17% ) and Occidental Energy Marketing, Inc. ( 13% ). For the year ended December 31, 2015 , three significant purchasers accounted for 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company ( 33% ), Enterprise Crude Oil LLC ( 14% ) and Sequent Energy Management, L.P. ( 12% ). For the year ended December 31, 2014 , three significant purchasers accounted for approximately 68% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company ( 45% ), Enterprise Crude Oil LLC ( 12% ) and Enterprise Products Operating LLC ( 11% ). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2016, 2015 and 2014 , approximately 38% , 39% and 44% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Stock-Based Compensation +The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units. +The Company’s consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 include a stock-based compensation (non-cash) expense of $12.4 million , $9.5 million and $5.5 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.0 million , $0.9 million and $0.3 million in 2016 , 2015 and 2014 , respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2016, 2015 and 2014 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2016, 2015 and 2014 . +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings (Loss) Per Common Share +The Company reports basic earnings (loss) per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2016, 2015 and 2014 (in thousands, except per share data). +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Year Ended December 31, +2016 +2015 +2014 +Net (loss) income attributable to Matador Resources Company shareholders — numerator +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +Weighted average common shares outstanding — denominator +Basic +91,273 +81,537 +70,229 +Dilutive effect of options, restricted stock units and preferred shares +— +— +677 +Diluted weighted average common shares outstanding +91,273 +81,537 +70,906 +Earnings (loss) per common share attributable to +Matador Resources Company shareholders +Basic +$ +(1.07 +) +$ +(8.34 +) +$ +1.58 +Diluted +$ +(1.07 +) +$ +(8.34 +) +$ +1.56 +A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company. +A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2016 were with Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s Credit Agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Revenue from Contracts with Customers . In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company will adopt the new guidance effective January 1, 2018. The Company is evaluating the new guidance, including (i) identification of revenue streams, (ii) review of contracts and procedures currently in place and (iii) which adoption method it will use. +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. +Leases . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements. +Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) , which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The update should be applied using a retrospective transition method to each period presented. The Company believes that the impact of the adoption of this ASU will change the presentation of its beginning and ending cash balances on its Consolidated Statements of Cash Flows and eliminate the presentation of changes in restricted cash balances from investing activities on its Consolidated Statements of Cash Flows. +Clarifying the Definition of a Business. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) , which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017 with early adoption permitted. Entities are required to apply guidance prospectively upon adoption. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements. +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2016 and 2015 (in thousands). +December 31, +2016 +2015 +Oil and natural gas properties +Evaluated (subject to amortization) +$ +2,408,305 +$ +2,122,174 +Unproved and unevaluated (not subject to amortization) +479,736 +387,504 +Total oil and natural gas properties +2,888,041 +2,509,678 +Accumulated depletion +(1,850,882 +) +(1,574,040 +) +Net oil and natural gas properties +1,037,159 +935,638 +Other property and equipment +Midstream equipment and facilities +145,662 +78,564 +Furniture, fixtures and other equipment +5,487 +2,918 +Software +3,206 +2,193 +Land +1,437 +1,539 +Leasehold improvements +5,003 +1,173 +Total other property and equipment +160,795 +86,387 +Accumulated depreciation +(13,429 +) +(9,619 +) +Net other property and equipment +147,366 +76,768 +Net property and equipment +$ +1,184,525 +$ +1,012,406 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2016 and the year in which these costs were incurred (in thousands). +Description +2016 +2015 +2014 +2013 and prior +Total +Costs incurred for +Property acquisition +$ +126,857 +$ +236,507 +$ +55,258 +$ +23,654 +$ +442,276 +Exploration wells +19,017 +3,375 +34 +— +22,426 +Development wells +13,086 +1,218 +730 +— +15,034 +Total +$ +158,960 +$ +241,100 +$ +56,022 +$ +23,654 +$ +479,736 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2016 are related primarily to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past four years. These costs include, in particular, the cost of the acreage acquired as part of the HEYCO Merger (as described and defined in Note 5) in 2015. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties which are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $37.5 million at December 31, 2016 . Of this +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +total, $22.4 million was associated with exploration wells and $15.0 million was associated with development wells. The Company anticipates that most of the $37.5 million associated with these wells in progress at December 31, 2016 will be transferred to the amortization base during 2017 . +NOTE 4 — ASSET RETIREMENT OBLIGATIONS +In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2016 and 2015 (in thousands). +Year Ended December 31, +2016 +2015 +Beginning asset retirement obligations +$ +15,420 +$ +11,951 +Liabilities incurred during period +1,791 +4,508 +Liabilities settled during period +(375 +) +(588 +) +Revisions in estimated cash flows +2,622 +(1,185 +) +Accretion expense +1,182 +734 +Ending asset retirement obligations +20,640 +15,420 +Less: current asset retirement obligations (1) +(915 +) +(254 +) +Long-term asset retirement obligations +$ +19,725 +$ +15,166 +__________________ +(1) +Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2016 and 2015 . +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES +Business Combinations +On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross ( 18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction. +As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Matador incurred an additional $4.5 million for customary purchase price adjustments, including adjusting for production, revenues and operating and capital expenditures from September 1, 2014 to closing. The consideration paid and the liabilities assumed, including deferred tax liabilities of approximately $76.8 million and other liabilities of approximately $4.5 million , represent a total purchase price of $223.5 million . The HEYCO Merger was accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +The majority of the assets acquired in the HEYCO Merger were in the form of non-producing acreage. The producing wells acquired in the HEYCO Merger did not have a material impact on the Company’s revenues or results of operations for the year ended December 31, 2015 . During the year ended December 31, 2015 , the Company incurred approximately $2.5 million of transaction costs associated with the HEYCO Merger, which were included in “General and administrative” costs in the consolidated statement of operations. +Divestitures +On October 1, 2015 , the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant. +Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and the Company received net proceeds of approximately $139.8 million , after deducting customary purchase price adjustments of approximately $3.6 million . In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement. +Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15 -year term of the gathering and processing agreement. +During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink is now processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing agreement the Company entered into with EnLink is no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016 . +The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017 these assets were contributed to the Joint Venture (as described and defined in Note 18). +NOTE 6 — DEBT +Credit Agreement +On September 28, 2012 , the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million . MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. On October 31, 2016, the borrowing base was increased from $300.0 million to $400.0 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at June 30, 2016 +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 6 — DEBT — Continued +using commodity price estimates prescribed by the lenders. This borrowing base increase was primarily attributable to increases in both the Company’s proved reserves volumes and increases in oil and natural gas prices in the latter part of 2016. All other provisions of the Credit Agreement remained unchanged. This October 2016 redetermination constituted the regularly scheduled November 1 redetermination. The Credit Agreement matures on October 16, 2020. +In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. Total deferred loan costs were $1.3 million at December 31, 2016 , and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +During the year ended December 31, 2016 , using a portion of the net proceeds from the December 2016 senior unsecured notes offering and the public offering of our common stock discussed herein, the Company repaid a total of $120.0 million of its outstanding borrowings under the Credit Agreement. At December 31, 2016 , the Company had no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. At February 22, 2017 , the Company continued to have no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. +A commitment fee of 0.375% to 0.50% , depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of the Company’s assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; +• +engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and +• +take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 6 — DEBT — Continued +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving the Company or its subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2016 . +Senior Unsecured Notes +On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes are Matador’s senior unsecured obligations, are redeemable as described below and were issued at par value. The net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Original Notes mature on April 15, 2023 and interest is payable semi-annually in arrears on April 15 and October 15 of each year. +On October 21, 2015, and pursuant to a registered exchange offer, the Company exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Registered Notes. +On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes” and, collectively with the Registered Notes, the “Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5% . We received net proceeds from the Notes Offering of approximately $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. A portion of the net proceeds of the Notes Offering, along with the proceeds from the December 2016 public offering of our common stock, have been used to partially fund certain acreage acquisitions and midstream asset development, to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig. The Notes are our senior unsecured obligations and are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year. +On or after April 15, 2018 , Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of the years indicated. +Year +Redemption Price +2018 +105.156% +2019 +103.438% +2020 +101.719% +2021 and thereafter +100.000% +At any time prior to April 15, 2018 , Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 6 — DEBT — Continued +In addition, at any time prior to April 15, 2018 , Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date. +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company; +• +consolidate, merge or transfer all or substantially all of its assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• +default for 30 days in the payment when due of interest on the Notes; +• +default in the payment when due of the principal of, or premium, if any, on the Notes; +• +failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets; +• +failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture; +• +failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture; +• +payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more; +• +failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; +• +any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and +• +certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 7 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2016 and 2015 , respectively, is as follows (in thousands). +December 31, +2016 +2015 +Deferred tax assets +Unrealized loss on derivatives +$ +8,734 +$ +— +Net operating loss carryforwards +137,757 +79,208 +Alternative minimum tax carryforward +8,633 +9,785 +Percentage depletion carryover +2,595 +2,442 +Property and equipment +44,391 +42,757 +Deferred gain on sale leaseback transaction +— +32,831 +Other +— +7,396 +Total deferred tax assets +202,110 +174,419 +Valuation allowance on deferred tax assets +(190,255 +) +(154,320 +) +Total deferred tax assets, net of valuation allowance +11,855 +20,099 +Deferred tax liabilities +Unrealized gain on derivatives +(3,800 +) +(5,699 +) +Other +(8,055 +) +(14,400 +) +Total deferred tax liabilities +(11,855 +) +(20,099 +) +Net deferred tax liabilities +$ +— +$ +— +At December 31, 2016 , the Company had net operating loss carryforwards of $375.9 million for federal income tax purposes and $6.2 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the State of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . +As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015 , the Company recorded an impairment charge of $158.6 million and $801.2 million , respectively, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2016 and 2015, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded in 2015 and 2016. As a result, at December 31, 2016 and 2015, the Company maintained a valuation allowance against the Company’s federal and state deferred tax assets. The valuation allowance will continue to be recognized until the realization of future tax benefits are more likely than not to be utilized. +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 7 — INCOME TAXES — Continued +The current income tax provision for the years ended December 31, 2016, 2015 and 2014 , respectively, was comprised of the following (in thousands). +Year Ended December 31, +2016 +2015 +2014 +Current income tax provision +State income tax +$ +108 +$ +371 +$ +— +Federal alternative minimum tax +(1,144 +) +2,588 +133 +Net current income tax (benefit) provision +$ +(1,036 +) +$ +2,959 +$ +133 +Reconciliations of the tax (benefit) expense computed at the statutory federal rate to the Company’s total income tax (benefit) provision for the years ended December 31, 2016, 2015 and 2014 , respectively, is as follows (in thousands). +Year Ended December 31, +2016 +2015 +2014 +Federal tax (benefit) expense at statutory rate (1) +$ +(34,333 +) +$ +(289,412 +) +$ +61,301 +State income tax +539 +(13,215 +) +2,707 +Permanent differences (2) +(499 +) +698 +397 +Federal alternative minimum tax +1,144 +(2,588 +) +(133 +) +Change in federal valuation allowance +33,688 +145,777 +— +Change in state valuation allowance +(539 +) +8,413 +(30 +) +Net deferred income tax (benefit) provision +— +(150,327 +) +64,242 +Net current income tax (benefit) provision +(1,036 +) +2,959 +133 +Total income tax (benefit) provision +$ +(1,036 +) +$ +(147,368 +) +$ +64,375 +__________________ +(1) +The statutory federal tax rate was 35% for the years ended December 31, 2016, 2015 and 2014 . +(2) +Amount is primarily attributable to stock-based compensation. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2012 . The earliest tax year open for examination by the State of Texas is 2009. During the year ended December 31, 2016 , the Company’s 2009 and 2010 franchise tax returns were under examination by the State of Texas. This examination has been completed with no additional tax due; however, the examination has not been formally closed. In addition, as of December 31, 2016, the Company’s 2013 federal income tax return was under examination by the Internal Revenue Service. This examination has been completed with no additional tax due; however, the examination has not been formally closed. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2016 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 8 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. +In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2016 , the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. +The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period. +Stock Options +Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five or ten years. +The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2016, 2015 and 2014 . +2016 +2015 +2014 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +3.14 years +0.39 years +1.51 years +Risk-free interest rate +1.70% +0.64% +0.74% +Volatility +47.07% +91.98% +55.14% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +—% +—% +—% +The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2016, 2015 and 2014 . +2016 +2015 +2014 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +3.96 years +4.00 years +3.99 years +Risk-free interest rate +1.08% +1.15% +1.21% +Volatility +45.68% +56.89% +51.47% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +1.16% +3.21% +4.28% +Weighted average fair value of stock option awards granted during the year +$5.65 +$9.90 +$9.45 +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2016 under the 2003 Plan and the 2012 Incentive Plan is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2015 +2,363 +$ +15.40 +Options granted +668 +$ +15.51 +Options exercised +(114 +) +$ +10.12 +Options forfeited +(28 +) +$ +19.73 +Options expired +(2 +) +$ +22.66 +Options outstanding at December 31, 2016 +2,887 +$ +15.59 +Options outstanding at +December 31, 2016 +Options exercisable at +December 31, 2016 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life +Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$8.18 - $9.55 +816 +1.30 +$ +8.30 +484 +$ +8.35 +$10.49 - $17.80 +925 +2.87 +$ +13.55 +302 +$ +10.58 +$18.77 - $22.70 +862 +3.05 +$ +21.84 +65 +$ +21.21 +$23.40 - $27.33 +284 +2.26 +$ +24.22 +112 +$ +23.49 +At December 31, 2016 , the aggregate intrinsic value was $29.4 million for outstanding options and $13.6 million for exercisable options, based on the Company’s quoted closing market price of $25.76 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2016 was 1.19 years. +The total intrinsic value of options exercised during the years ended December 31, 2016, 2015 and 2014 was $1.6 million , $1.3 million and $0.2 million , respectively. The tax related benefit realized from the exercise of stock options totaled $0.5 million , $0.3 million and $0.1 million for the years ended December 31, 2016, 2015 and 2014 , respectively. +During the years ended December 31, 2016, 2015 and 2014 , the Company recognized $5.9 million , $4.7 million and $2.5 million , respectively, in stock-based compensation expense attributable to stock options. At December 31, 2016, 2015 and 2014 , the Company had recorded $1.4 million , zero and $1.4 million of long-term liabilities and zero , $1.0 million and zero of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2016, 2015 and 2014 , respectively. +At December 31, 2016 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $6.9 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.90 years. +The fair value of options vested during 2016 , 2015 and 2014 was $3.0 million , $1.3 million and $1.5 million , respectively. +Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +makes an election to defer issuance for a set term after vesting. One current director elected to defer the issuance of his awards in 2015, 2014 and 2013. All awards granted in 2016, 2015 and 2014 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2016 were granted under the 2012 Incentive Plan. +A summary of the non-vested restricted stock and restricted stock units as of December 31, 2016 is presented below (in thousands, except fair value). +Restricted Stock +Restricted Stock Units +Non-vested restricted stock and +restricted stock units +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value +Non-vested at December 31, 2015 +854 +$ +17.64 +68 +$ +21.89 +Granted +472 +$ +18.55 +66 +$ +19.44 +Vested +(225 +) +$ +16.05 +(52 +) +$ +19.67 +Forfeited +(62 +) +$ +20.49 +— +— +Non-vested at December 31, 2016 +1,039 +$ +18.23 +82 +$ +21.32 +At December 31, 2016 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $28.9 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $25.76 per share on that date. +During the years ended December 31, 2016, 2015 and 2014 , the Company recognized approximately $6.6 million , $4.7 million and $3.0 million , respectively, in stock-based compensation expense attributable to restricted stock and restricted stock units. +At December 31, 2016 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $12.5 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.8 years. +The fair value of restricted stock and restricted stock units vested during 2016 , 2015 and 2014 was $4.6 million , $0.8 million and $0.9 million , respectively. +The total tax benefit recognized for all stock-based compensation was $4.3 million , $3.4 million and $1.9 million for the years ended December 31, 2016, 2015 and 2014 , respectively. +In mid-February 2017, the Company granted awards of 228,174 shares of restricted stock and options to purchase 590,128 shares of the Company’s common stock at an exercise price of $27.26 per share to certain of its employees. The fair value of these awards was approximately $12.4 million . All of these awards vest ratably over three years. +In mid-February 2017, the Company also granted awards of 174,561 shares of restricted stock and options to purchase 444,491 shares of the Company’s common stock at an exercise price of $26.86 per share to certain of its employees. The fair value of these awards was approximately $9.3 million . All of these awards vest ratably over three years. +NOTE 9 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled approximately $0.7 million , $0.6 million and $0.4 million in 2016 , 2015 and 2014 , respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $0.9 million , $0.8 million and $0.5 million in 2016 , 2015 and 2014 , respectively. The Company made no additional discretionary contributions in any reporting period presented. +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 10 — EQUITY +Stock Offerings, Retirement and Issuances +On December 9, 2016 , the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million , the Company received net proceeds of approximately $145.8 million . A portion of the net proceeds of the public offering, along with the proceeds from the Notes Offering (see Note 6), have been used to partially fund certain acreage acquisitions and midstream asset development, to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital expenditures associated with the addition of a fourth drilling rig. +On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million , the Company received net proceeds of approximately $141.5 million , which were used for general corporate purposes, including to fund a portion of the Company’s 2016 capital expenditures. +As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. +On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2016 to satisfy certain conditions under the merger agreement. +On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million , the Company received net proceeds of approximately $187.6 million . +On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting direct offering costs totaling approximately $0.6 million , the Company received net proceeds of approximately $181.3 million . +Treasury Stock +On October 27, 2016, October 30, 2015 and October 31, 2014, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2016, September 30, 2015 and September 30, 2014, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2016 , 2015 and 2014 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +The Company typically uses costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide the Company with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +At December 31, 2016 , we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any oil contract is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. +When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract natural gas liquids volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract natural gas liquids volume +At December 31, 2016 , the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2017 and 2018. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2016 . +Notional Quantity (Bbl or MMBtu) +Weighted Average Price Floor ($/Bbl or +$/MMBtu) +Weighted Average Price Ceiling ($/Bbl or +$/MMBtu) +Fair Value of Liabilities (thousands) +Commodity +Calculation Period +Oil +01/01/2017 - 12/31/2017 +2,760,000 +$ +41.39 +$ +51.88 +$ +(18,316 +) +Oil +01/01/2018 - 12/31/2018 +720,000 +$ +43.75 +$ +63.90 +(751 +) +Natural Gas +01/01/2017 - 12/31/2017 +16,860,000 +$ +2.40 +$ +3.59 +(5,887 +) +Total open derivative financial instruments +$ +(24,954 +) +Subsequent to December 31, 2016, the Company entered into various costless collar contracts for oil. The costless collar contracts for oil included approximately 1,890,000 Bbl in 2017 with a weighted average floor price of $50.00 per Bbl and a weighted average ceiling price of $60.75 per Bbl. +From time-to-time we enter into derivative financial instruments with certain counterparties. These derivative financial instruments are subject to master netting arrangements; all but one counterparty allow for cross-commodity master netting provided the settlements dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2016 and December 31, 2015 (in thousands). +Derivative Instruments +Gross amounts recognized +Gross amounts netted in the consolidated balance sheets +Net amounts presented in the consolidated balance sheets +December 31, 2016 +Current liabilities +$ +(24,203 +) +$ +— +$ +(24,203 +) +Other liabilities +(751 +) +— +(751 +) +Total +$ +(24,954 +) +$ +— +$ +(24,954 +) +December 31, 2015 +Current assets +$ +16,767 +$ +(483 +) +$ +16,284 +Current liabilities +(483 +) +483 +— +Total +$ +16,284 +$ +— +$ +16,284 +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. +Year Ended December 31, +Type of Instrument +Location in Statement of Operations +2016 +2015 +2014 +Derivative Instrument +Oil +Revenues: Realized gain on derivatives +$ +5,851 +$ +62,259 +$ +5,221 +Natural Gas +Revenues: Realized gain (loss) on derivatives +3,435 +12,653 +(718 +) +Natural Gas Liquids (NGL) +Revenues: Realized gain on derivatives +— +2,182 +519 +Realized gain on derivatives +9,286 +77,094 +5,022 +Oil +Revenues: Unrealized (loss) gain on derivatives +(18,969 +) +(31,897 +) +47,178 +Natural Gas +Revenues: Unrealized (loss) gain on derivatives +(22,269 +) +(5,440 +) +9,087 +Natural Gas Liquids (NGL) +Revenues: Unrealized (loss) gain on derivatives +— +(1,928 +) +2,037 +Unrealized (loss) gain on derivatives +(41,238 +) +(39,265 +) +58,302 +Total +$ +(31,952 +) +$ +37,829 +$ +63,324 +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 12 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 +Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 +Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 +Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +At December 31, 2016 and 2015 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities. +At December 31, 2016 and 2015 , the fair value of the Company’s Notes was $605.2 million and $381.0 million , respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2016 and 2015 (in thousands). +Fair Value Measurements at +December 31, 2016 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil and natural gas derivatives +$ +— +$ +(24,954 +) +$ +— +$ +(24,954 +) +Total +$ +— +$ +(24,954 +) +$ +— +$ +(24,954 +) +Fair Value Measurements at +December 31, 2015 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil and natural gas derivatives +$ +— +$ +16,284 +$ +— +$ +16,284 +Total +$ +— +$ +16,284 +$ +— +$ +16,284 +Additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination (see Note 5), lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 12 — FAIR VALUE MEASUREMENTS — Continued +sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2016 and 2015 . The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions. +NOTE 13 — COMMITMENTS AND CONTINGENCIES +Office Lease +The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026 . The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease. +From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties. +The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2016 (in thousands). +Year Ending December 31, +Amount +2017 +$ +2,443 +2018 +2,495 +2019 +2,528 +2020 +2,602 +2021 +2,660 +Thereafter +12,335 +Total +$ +25,063 +Rent expense, including fees for operating expenses and consumption of electricity, was $2.9 million , $1.7 million , and $0.9 million for 2016 , 2015 and 2014 , respectively. +Natural Gas and NGL Processing and Transportation Commitments +Eagle Ford +Effective September 1, 2012 , the Company entered into a firm five -year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period. +Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain prior periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement waived the deficiency fee. The Company paid approximately $3.0 million and $5.5 million in processing and transportation fees under this agreement during the years ended December 31, 2016 and 2015 , respectively. The future undiscounted minimum payment under this agreement as of December 31, 2016 is $1.2 million in 2017. +Delaware Basin +As part of the sale of the Loving County Processing System (see Note 5), the Company entered into a 15-year fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued +commitment for transportation and processing at the facilities in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2016 , the total deficiency fee required to be paid would be approximately $11.7 million . In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $9.8 million and $1.8 million in processing and gathering fees under this agreement during the years ended December 31, 2016 and 2015 , respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which have typically been for two years or less. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $46.3 million at December 31, 2016 . +At December 31, 2016 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $11.1 million at December 31, 2016 . The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 14 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2016 and 2015 (in thousands). +December 31, +2016 +2015 +Accrued evaluated and unproved and unevaluated property costs +$ +54,273 +$ +54,586 +Accrued support equipment and facilities costs +15,139 +17,393 +Accrued lease operating expenses +16,009 +7,743 +Accrued interest on debt +6,541 +5,806 +Accrued asset retirement obligations +915 +254 +Accrued partners’ share of joint interest charges +5,572 +4,565 +Other +3,011 +2,022 +Total accrued liabilities +$ +101,460 +$ +92,369 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2016, 2015 and 2014 (in thousands). +Year Ended December 31, +2016 +2015 +2014 +Cash paid for income taxes +$ +2,895 +$ +506 +$ +94 +Cash paid for interest expense, net of amounts capitalized +27,464 +16,154 +5,269 +Increase in asset retirement obligations related to mineral properties +3,817 +2,510 +3,843 +Increase in asset retirement obligations related to support equipment and facilities +222 +383 +120 +Increase (decrease) in liabilities for oil and natural gas properties capital expenditures +1,775 +(30,683 +) +32,972 +(Decrease) increase in liabilities for support equipment and facilities +(588 +) +12,076 +4,290 +Issuance of restricted stock units for Board and advisor services +992 +584 +444 +Stock-based compensation expense recognized as liability +569 +79 +223 +Increase in liabilities for accrued cost to issue equity +343 +— +— +Transfer of inventory to oil and natural gas properties +395 +615 +216 +NOTE 15 — SUBSIDIARY GUARANTORS +Matador filed a registration statement on Form S-3 with the SEC in 2013, which became effective on May 9, 2013, and a registration statement on Form S-3 with the SEC in 2014, which became effective upon filing on May 22, 2014, registering, in each case, among other securities, senior and subordinated debt securities and guarantees of debt securities by certain subsidiaries of Matador (the “Shelf Guarantor Subsidiaries”). On April 14, 2015, the Company issued the Original Notes and on December 9, 2016, the Company issued the Additional Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Notes Guarantor Subsidiaries” and, together with the Shelf Guarantor Subsidiaries, the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2016 , the Guarantor Subsidiaries were 100% owned by Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries were minor. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 16 — RELATED PARTY TRANSACTIONS +In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2016 , the Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. +NOTE 17 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During the third quarter of 2016, our midstream business became a reportable segment under U.S. GAAP. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. +The following tables present selected financial information for the periods presented regarding the Company’s operating segments on a stand-alone basis, expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 17 — SEGMENT INFORMATION — Continued +Exploration and Production +Consolidated Company +Midstream +Corporate +Eliminations +Year Ended December 31, 2016 +Oil and natural gas revenues +$ +289,512 +$ +1,644 +$ +— +$ +— +$ +291,156 +Midstream services revenues +— +18,982 +— +(13,764 +) +5,218 +Realized gain on derivatives +9,286 +— +— +— +9,286 +Unrealized gain on derivatives +(41,238 +) +— +— +— +(41,238 +) +Expenses (1) +391,098 +8,254 +56,001 +(13,764 +) +441,589 +Operating (loss) income (2) +$ +(133,538 +) +$ +12,372 +$ +(56,001 +) +$ +— +$ +(177,167 +) +Total Assets +$ +1,098,525 +$ +140,459 +$ +225,681 +$ +— +$ +1,464,665 +Capital Expenditures +$ +379,881 +$ +67,566 +$ +6,913 +$ +— +$ +454,360 +_____________________ +(1) Expenses include depreciation, depletion and amortization expenses of $118.4 million , $2.7 million and $0.9 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment. +(2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production +Consolidated Company +Midstream +Corporate +Eliminations +Year Ended December 31, 2015 +Oil and natural gas revenues +$ +277,844 +$ +496 +$ +— +$ +— +$ +278,340 +Midstream services revenues +— +11,485 +— +(9,621 +) +1,864 +Realized gain on derivatives +77,094 +— +— +— +77,094 +Unrealized loss on derivatives +(39,265 +) +— +— +— +(39,265 +) +Expenses (1) +1,078,534 +5,178 +50,604 +(9,621 +) +1,124,695 +Operating (loss) income (2) +$ +(762,861 +) +$ +6,803 +$ +(50,604 +) +$ +— +$ +(806,662 +) +Total Assets +$ +1,000,075 +$ +75,980 +$ +64,806 +$ +— +$ +1,140,861 +Capital Expenditures (3) +$ +622,642 +$ +75,009 +$ +786 +$ +— +$ +698,437 +_____________________ +(1) Expenses include depreciation, depletion and amortization expenses of $176.7 million , $1.6 million and $0.5 million for the exploration and production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment. +(2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) In October 2015, the Company sold the Wolf Processing Plant to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets. +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 17 — SEGMENT INFORMATION — Continued +Exploration and Production +Consolidated Company +Midstream +Corporate +Eliminations +Year Ended December 31, 2014 +Oil and natural gas revenues +$ +366,191 +$ +1,521 +$ +— +$ +— +$ +367,712 +Midstream services revenues +— +4,929 +— +(3,716 +) +1,213 +Realized gain on derivatives +5,022 +— +— +— +5,022 +Unrealized loss on derivatives +58,302 +— +— +— +58,302 +Expenses (1) +220,374 +2,703 +32,557 +(3,716 +) +251,918 +Operating (loss) income (2) +$ +209,141 +$ +3,747 +$ +(32,557 +) +$ +— +$ +180,331 +Total Assets +$ +1,388,261 +$ +35,100 +$ +11,129 +$ +— +$ +1,434,490 +Capital Expenditures +$ +597,351 +$ +12,504 +$ +517 +$ +— +$ +610,372 +_____________________ +(1) Expenses include depreciation, depletion and amortization expenses of $133.1 million , $1.2 million and $0.4 million for the exploration and production, midstream and corporate segments, respectively. +(2) Includes $17,000 in net loss attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 18 — SUBSEQUENT EVENTS +Subsequent to December 31, 2016, the Company acquired approximately 13,900 gross ( 8,200 net) leased and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around its existing acreage in the Delaware Basin. The cost of these acquisitions was approximately $111 million . +On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks and Wolf asset areas to San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (“Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company will continue to operate the Delaware Midstream Assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of the Joint Venture. +The Company and Five Point own 51% and 49% of the Joint Venture, respectively. Five Point provided initial cash consideration of $176.4 million to the Joint Venture in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by the Joint Venture to the Company as a special distribution. The Company may earn an additional $73.5 million in performance incentives over the next five years . The Company contributed the Delaware Midstream Assets and $5.1 million in cash to the Joint Venture in exchange for its 51% interest. The parties to the Joint Venture have also committed to spend up to an additional $140 million in the aggregate to expand the Joint Venture’s midstream operations and asset base. +In connection with the Joint Venture, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15 -year, fixed fee natural gas processing agreement (when combined with the gathering and salt water disposal agreements, the “Operational Agreements”). The Joint Venture will provide the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at inception was approximately $273.5 million . +The following unaudited pro forma consolidated financial information is presented to illustrate the effect on the historical operating results and financial position of the Company of (a) the formation of San Mateo and the transactions associated with the Joint Venture and (b) the Company’s acquisition on February 14, 2017 of the remaining non-controlling interest in Fulcrum Delaware Water Resources, LLC (“Fulcrum Delaware Water Resources”) not previously owned by the Company for approximately $2.6 million (collectively, the “Transactions”). +The Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2016, if presented, would contain an adjustment of $4.5 million to increase the net income attributable to non-controlling interest in subsidiaries from $0.4 million to $4.9 million , which would increase the net loss attributable to Matador Resources Company shareholders from $97.4 million to $102.0 million , and an adjustment of $0.05 per diluted common share to increase the net loss per diluted common share attributable to Matador Resources Company shareholders from $1.07 to $1.12 . +The following Unaudited Pro Forma Consolidated Balance Sheet as of December 31, 2016, presented for illustrative purposes, is based on the historical financial statements of the Company as of December 31, 2016, after giving effect to the Transactions as if they had occurred on December 31, 2016. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 18 — SUBSEQUENT EVENTS — Continued +UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET +December 31, 2016 +As Reported +Adjustment +Pro Forma +ASSETS +Current assets +Cash +$ +212,884 +$ +164,340 +(1) +$ +377,224 +Restricted cash +1,258 +9,407 +(2) +10,665 +Accounts receivable +— +Oil and natural gas revenues +34,154 +— +34,154 +Joint interest billings +19,347 +— +19,347 +Other +5,167 +— +5,167 +Lease and well equipment inventory +3,045 +— +3,045 +Prepaid expenses and other assets +3,327 +— +3,327 +Total current assets +279,182 +173,747 +452,929 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +2,408,305 +— +2,408,305 +Unproved and unevaluated +479,736 +— +479,736 +Other property and equipment +160,795 +— +160,795 +Less accumulated depletion, depreciation and amortization +(1,864,311 +) +— +(1,864,311 +) +Net property and equipment +1,184,525 +— +1,184,525 +Other assets +958 +958 +Total assets +$ +1,464,665 +$ +173,747 +$ +1,638,412 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +4,674 +$ +— +$ +4,674 +Accrued liabilities +101,460 +— +101,460 +Royalties payable +23,988 +— +23,988 +Amounts due to affiliates +8,651 +— +8,651 +Derivative instruments +24,203 +— +24,203 +Advances from joint interest owners +1,700 +— +1,700 +Amounts due to joint ventures +4,251 +— +4,251 +Other current liabilities +578 +— +578 +Total current liabilities +169,505 +— +169,505 +Long-term liabilities +Senior unsecured notes payable +573,924 +— +573,924 +Asset retirement obligations +19,725 +— +19,725 +Derivative instruments +751 +— +751 +Amounts due to joint ventures +1,771 +— +1,771 +Other long-term liabilities +7,544 +— +7,544 +Total long-term liabilities +603,715 +— +603,715 +Commitments and contingencies (Note 13) +Shareholders’ equity +Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively +995 +— +995 +Additional paid-in capital +1,325,481 +124,871 +(3) +1,450,352 +Accumulated deficit +(636,351 +) +— +(636,351 +) +Total Matador Resources Company shareholders’ equity +690,125 +124,871 +814,996 +Non-controlling interest in subsidiaries +1,320 +48,876 +(4) +50,196 +Total shareholders’ equity +691,445 +173,747 +865,192 +Total liabilities and shareholders’ equity +$ +1,464,665 +$ +173,747 +$ +1,638,412 +______________________ +(1) +Represents $176.4 million of cash contributed by Five Point in connection with the formation of San Mateo less (i) approximately $2.6 million paid by the Company to acquire the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and (ii) $10.0 +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2016, 2015 and 2014 +NOTE 18 — SUBSEQUENT EVENTS — Continued +million of cash restricted to operations of San Mateo. Also reflects $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources not previously owned by the Company. +(2) +Represents $10.0 million in cash contributed to San Mateo less $0.6 million released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own. +(3) +Reflects the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and the amount received in connection with the formation of San Mateo. +(4) +Represents the adjustment required to reflect the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and Five Point’s 49% non-controlling interest in San Mateo. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2016, 2015 and 2014 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2016, 2015 and 2014 (in thousands). +Year Ended December 31, +2016 +2015 +2014 +Property acquisition costs +Proved +$ +— +$ +16,524 +$ +2,728 +Unproved and unevaluated +108,206 +253,923 +78,484 +Exploration costs +113,562 +122,495 +156,178 +Development costs +158,113 +229,700 +359,961 +Total costs incurred (1) +$ +379,881 +$ +622,642 +$ +597,351 +__________________ +(1) +Excludes midstream-related development and corporate costs of approximately $74.5 million, $75.8 million and $13.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2016, 2015 and 2014 , most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $4.4 million , $3.3 million and $4.0 million for the years ended December 31, 2016, 2015 and 2014 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $15.7 million , $6.9 million and $6.4 million of these internal costs in 2016 , 2015 and 2014 , respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $3.7 million , $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016 , 2015 and 2014 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2016, 2015 and 2014 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2016, 2015 and 2014 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014 , these average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2016, 2015 and 2014 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2013 +16,362 +212,195 +51,729 +Revisions of prior estimates +(1,196 +) +164 +(1,169 +) +Purchases of minerals in-place +10 +433 +82 +Extensions and discoveries +12,328 +69,566 +23,921 +Production +(3,320 +) +(15,303 +) +(5,870 +) +Total at December 31, 2014 +24,184 +267,055 +68,693 +Revisions of prior estimates +(2,609 +) +(75,433 +) +(15,181 +) +Purchases of minerals in-place +1,102 +2,927 +1,589 +Extensions and discoveries +27,459 +70,054 +39,135 +Production +(4,492 +) +(27,702 +) +(9,109 +) +Total at December 31, 2015 +45,644 +236,901 +85,127 +Revisions of prior estimates +(6,440 +) +(28,481 +) +(11,187 +) +Extensions and discoveries +22,869 +114,730 +41,992 +Production +(5,096 +) +(30,501 +) +(10,180 +) +Total at December 31, 2016 +56,977 +292,649 +105,752 +Proved Developed Reserves +December 31, 2013 +8,258 +53,458 +17,168 +December 31, 2014 +14,053 +102,795 +31,185 +December 31, 2015 +17,129 +101,447 +34,037 +December 31, 2016 +22,604 +126,759 +43,731 +Proved Undeveloped Reserves +December 31, 2013 +8,104 +158,737 +34,561 +December 31, 2014 +10,131 +164,260 +37,508 +December 31, 2015 +28,515 +135,454 +51,090 +December 31, 2016 +34,373 +165,890 +62,021 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2016, 2015 and 2014 . +The Company’s proved oil and natural gas reserves increased to 105,752 MBOE at December 31, 2016 from 85,127 MBOE at December 31, 2015 . The Company’s proved oil and natural gas reserves increased by 30,805 MBOE and the Company produced 10,180 MBOE during the year ended December 31, 2016 , resulting in a net increase of 20,625 MBOE. An increase of 41,992 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 11,187 MBOE during 2016 as a result of the reclassification of proved undeveloped reserves to contingent resources, primarily due to the decline in weighted average commodity prices used to estimate proved reserves during 2016, as compared to 2015. The Company anticipates that these contingent resources may be reclassified to proved undeveloped reserves in future periods should the oil and natural gas prices used to estimate proved reserves improve from the prices at December 31, 2016 . The Company’s proved developed oil and natural gas reserves increased to 43,731 MBOE at December 31, 2016 from 34,037 MBOE at December 31, 2015 , primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2016 , the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 41% proved developed and approximately 59% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from 68,693 MBOE at December 31, 2014. The Company’s proved oil and natural gas reserves increased by 25,543 MBOE and the Company produced 9,109 MBOE during the year ended December 31, 2015, resulting in a net increase of 16,434 MBOE. An +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2016, 2015 and 2014 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the removal of 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015, as well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves, primarily in the Haynesville shale in Northwest Louisiana, primarily resulting from the decline in commodity prices during 2015. The Company also purchased minerals in-place with proved reserves of 1,589 MBOE in 2015, primarily as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to 34,037 MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2015, the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately 60% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 68,693 MBOE at December 31, 2014 from 51,729 MBOE at December 31, 2013. The Company’s proved oil and natural gas reserves increased by 22,834 MBOE and the Company produced 5,870 MBOE during the year ended December 31, 2014, resulting in a net increase of 16,964 MBOE. An increase of 23,921 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, plus additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves decreased by 1,169 MBOE during the year as a result of revisions to previous estimates, primarily downward revisions of proved undeveloped oil reserves on certain of the Company’s undeveloped locations in the Eagle Ford shale play in South Texas in 2014. The Company also purchased minerals in-place with proved reserves of 82 MBOE in 2014. The Company’s proved developed oil and natural gas reserves increased to 31,185 MBOE at December 31, 2014 from 17,168 MBOE at December 31, 2013, primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale and in the Wolfcamp and Bone Spring plays in the Delaware Basin plus the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2014, the Company’s proved reserves were made up of approximately 35% oil and 65% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2016 , the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , the comparable average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014 , the comparable average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2016, 2015 and 2014 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 (in thousands). +Year Ended December 31, +2016 +2015 +2014 +Future cash inflows +$ +2,684,877 +$ +2,461,131 +$ +3,197,317 +Future production costs +(927,725 +) +(843,117 +) +(803,662 +) +Future development costs +(630,280 +) +(615,692 +) +(553,799 +) +Future income tax expense +(24,742 +) +(43,956 +) +(321,088 +) +Future net cash flows +1,102,130 +958,366 +1,518,768 +10% annual discount for estimated timing of cash flows +(527,087 +) +(429,185 +) +(605,449 +) +Standardized measure of discounted future net cash flows +$ +575,043 +$ +529,181 +$ +913,319 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 (in thousands). +Year Ended December 31, +2016 +2015 +2014 +Balance, beginning of period +$ +529,181 +$ +913,319 +$ +578,668 +Net change in sales and transfer prices and in production (lifting) costs related to future production +(92,477 +) +(509,901 +) +87,067 +Changes in estimated future development costs +(74,142 +) +(145,861 +) +(150,447 +) +Sales and transfers of oil and natural gas produced during the period +(191,908 +) +(184,612 +) +(283,187 +) +Purchases of reserves in place +— +16,321 +1,838 +Net change due to extensions and discoveries +360,033 +401,895 +537,472 +Net change due to revisions in estimates of reserves quantities +(95,917 +) +(285,823 +) +(26,263 +) +Previously estimated development costs incurred during the period +84,519 +121,543 +187,459 +Accretion of discount +51,779 +82,574 +65,518 +Other +(1,962 +) +2,029 +5,492 +Net change in income taxes +5,937 +117,697 +(90,298 +) +Standardized measure of discounted future net cash flows +$ +575,043 +$ +529,181 +$ +913,319 +F-43 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2016, 2015 and 2014 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2016 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2016 +Oil and natural gas revenues +$ +94,815 +$ +83,079 +$ +69,336 +$ +43,926 +Third-party midstream services revenues +2,261 +1,566 +918 +473 +Realized (loss) gain on derivatives +(1,127 +) +885 +2,465 +7,063 +Unrealized (loss) gain on derivatives +(10,977 +) +3,203 +(26,625 +) +(6,839 +) +Expenses (1) +76,753 +71,879 +146,705 +146,252 +Other income (expense) (2) +96,196 +(5,948 +) +(5,136 +) +(6,038 +) +Income (loss) before income taxes +104,415 +10,906 +(105,747 +) +(107,667 +) +Income tax provision (benefit) +105 +(1,141 +) +— +— +Net income (loss) +104,310 +12,047 +(105,747 +) +(107,667 +) +Net (income) loss attributable to non-controlling interest in subsidiaries +(155 +) +(116 +) +(106 +) +13 +Net income (loss) attributable to +Matador Resources Company shareholders +$ +104,155 +$ +11,931 +$ +(105,853 +) +$ +(107,654 +) +Earnings (loss) per common share +Basic +$ +1.10 +$ +0.13 +$ +(1.15 +) +$ +(1.26 +) +Diluted +$ +1.09 +$ +0.13 +$ +(1.15 +) +$ +(1.26 +) +__________________ +(1) +Expenses for June 30 and March 31, 2016 included full-cost ceiling impairment charges of $78.2 million, and $80.5 million, respectively. +(2) +Other income (expense) for December 31, 2016 included gain on the sale of the Loving County Processing System of $104.1 million. See Note 5. +The following table presents selected unaudited quarterly financial information for 2015 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2015 +Oil and natural gas revenues +$ +56,212 +$ +71,815 +$ +87,848 +$ +62,465 +Third-party midstream services revenues +480 +569 +464 +351 +Realized gain on derivatives +24,948 +19,862 +13,780 +18,504 +Unrealized (loss) gain on derivatives +(13,909 +) +6,733 +(23,532 +) +(8,557 +) +Expenses (1) +290,751 +367,633 +319,140 +147,171 +Other expense +5,599 +6,665 +5,786 +2,180 +Loss before income taxes +(228,619 +) +(275,319 +) +(246,366 +) +(76,588 +) +Income tax provision (benefit) +1,677 +(33,305 +) +(89,350 +) +(26,390 +) +Net loss +(230,296 +) +(242,014 +) +(157,016 +) +(50,198 +) +Net income attributable to non-controlling interest in subsidiaries +(105 +) +(45 +) +(75 +) +(36 +) +Net loss attributable to +Matador Resources Company shareholders +$ +(230,401 +) +$ +(242,059 +) +$ +(157,091 +) +$ +(50,234 +) +Loss per common share attributable to Matador Resources Company shareholders +Basic +$ +(2.72 +) +$ +(2.86 +) +$ +(1.89 +) +$ +(0.68 +) +Diluted +$ +(2.72 +) +$ +(2.86 +) +$ +(1.89 +) +$ +(0.68 +) +__________________ +(1) +Expenses for December 31, September 30, June 30 and March 31, 2015 included full-cost ceiling impairment charges of $219.4 million, $285.7 million, $229.0 million and $67.1 million, respectively. +F-44 \ No newline at end of file diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/filing_metadata.csv b/raw/filings/0001520006/2016/0001520006-17-000074/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e8e54a6169a02561024fbd41e2fd73a0d4bc96a1 --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2017-03-01,2016-12-31,2017-03-01T16:33:53.000Z,0001520006-17-000074,mtdr10-k12312016.htm,10-K,13340984,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000152000617000074/mtdr10-k12312016.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000617000074/,2016,2016,1 diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/item1.txt b/raw/filings/0001520006/2016/0001520006-17-000074/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..0496d71f30d181a21ce6761c18fa1264a2d695fe --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/item1.txt @@ -0,0 +1,1261 @@ +Item 1. Business. +In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations primarily, as of February 17, 2017, through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of our exploration, development and production operations and provide natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment in 2016 , the successful execution of our business strategies led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also significantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important financing transactions in 2016 , including two equity offerings, an issuance of senior unsecured notes and an increase in the borrowing base under our Credit Agreement (as defined below). These transactions, as well as the formation of the Joint Venture in February 2017, increased our operational flexibility and further strengthened our balance sheet. +2 +Table of Contents +2016 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2016 , we achieved record oil, natural gas and average daily oil equivalent production. In 2016 , we produced 5.1 million Bbl of oil, an increase of 13% , as compared to 4.5 million Bbl of oil produced in 2015 . We also produced 30.5 Bcf of natural gas, an increase of 10% from 27.7 Bcf of natural gas produced in 2015 . Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, an increase of 12% , as compared to 24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, for the year ended December 31, 2015 . The increase in oil and natural gas production was primarily a result of our ongoing delineation and development operations in the Delaware Basin throughout 2016 , which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2016 , as compared to 49% for the year ended December 31, 2015 . +Increased Oil and Oil Equivalent Reserves +At December 31, 2016 , our estimated total proved oil and natural gas reserves were 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, an increase of 24% from December 31, 2015 . The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 9% and 7% to $575.0 million and $581.5 million , respectively, at December 31, 2016 , from $529.2 million and $541.6 million , respectively, at December 31, 2015 , primarily as a result of our ongoing delineation and development operations in the Delaware Basin. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 25% to 57.0 million Bbl at December 31, 2016 from 45.6 million Bbl at December 31, 2015 . Our proved natural gas reserves increased 24% to 292.6 Bcf at December 31, 2016 from 236.9 Bcf at December 31, 2015 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development operations in the Delaware Basin during 2016 . +At December 31, 2016 , proved developed reserves included 22.6 million Bbl of oil and 126.8 Bcf of natural gas, and proved undeveloped reserves included 34.4 million Bbl of oil and 165.9 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 41% and 54% , respectively, of our total proved oil and natural gas reserves at December 31, 2016 . Proved developed reserves and proved oil reserves comprised 40% and 54% , respectively, of our total proved oil and natural gas reserves at December 31, 2015 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past three years, as we continue to apply what we learned from our Eagle Ford shale and Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2017. +We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin in 2016 , including 40 gross (35.6 net) operated and 15 gross (1.4 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2016 . As a result, at December 31, 2016 , our total acreage position in the Delaware Basin had increased to approximately 163,700 gross ( 94,300 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been very pleased with the initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our six main asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Ranger and Twin Lakes asset areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 145% (2.5-fold) to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 , as compared to 6,518 BOE per day ( 26% of total oil equivalent production), including 4,648 Bbl of oil per day ( 38% of total oil production) and 11.2 MMcf of natural gas per day ( 15% of total natural gas production), in 2015 . We expect our Delaware Basin production to increase throughout 2017 as we continue the delineation and development of these asset areas. +3 +Table of Contents +Operational highlights in the Delaware Basin (as further described below in “—Principal Areas of Interest — Exploration and Production Segment—Southeast New Mexico and West Texas — Delaware Basin” and “—Midstream Segment”) in 2016 included: +• +our continued improvement in operational efficiencies throughout the Delaware Basin, particularly in our Rustler Breaks and Wolf asset areas, as we achieved improvements in both drilling times and well costs; +• +in our Rustler Breaks asset area, the continued delineation and development of previously tested horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—and the successful testing of a new, deeper bench of the Wolfcamp B interval, which is sometimes referred to as the Blair Shale; +• +in our Wolf asset area, continued development of the Wolfcamp A-XY interval as well as the significant improvement in well results in the Second Bone Spring, as compared to our initial tests in that interval; +• +in our Ranger asset area, the initial results from three wells completed in the Third Bone Spring formation on our Mallon leasehold, which tested at the highest 24-hour initial potential flow rates of any wells we have drilled to date in the Delaware Basin and which illustrate the potential of our northern Delaware Basin acreage position; +• +a positive test of the Strawn formation in our Twin Lakes asset area from the Olivine State 5-16S-37E TL #1, a vertical well; and +• +the significant progress made with our midstream operations including the start-up of our Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) and associated natural gas gathering system in our Rustler Breaks asset area, our initial salt water disposal well and facility and associated water gathering lines in our Rustler Breaks asset area and two additional salt water disposal wells and facilities in our Wolf asset area. +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or in Northwest Louisiana and East Texas during 2016 , although we did participate in the drilling and completion of 2 gross (less than 0.1 net) non-operated Eagle Ford shale wells and 15 gross (2.1 net) non-operated Haynesville shale wells that began producing in 2016 . +Financing Arrangements +On March 11, 2016, we completed a public offering of 7,500,000 shares of our common stock. After deducting offering costs totaling approximately $0.8 million , we received net proceeds of approximately $141.5 million . In late October 2016 , the lenders party to our third amended and restated credit agreement (the “Credit Agreement”), under which we had no borrowings outstanding at December 31, 2016 , increased our borrowing base from $300.0 million to $400.0 million . On December 9, 2016, we issued $175.0 million of our 6.875% senior unsecured notes due 2023 (the “Additional Notes”) in a private placement. We received net proceeds from the issuance of Additional Notes of $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. Also on December 9, 2016, we completed a public offering of 6,000,000 shares of our common stock. After deducting offering costs totaling approximately $0.4 million , we received net proceeds of approximately $145.8 million . See Notes 6 and 10 to the consolidated financial statements in this Annual Report for more details on each of the above items. +2017 Recent Developments +Between January 1, 2017 and February 22, 2017 , we acquired approximately 13,900 gross (8,200 net) leasehold and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly in and around our existing acreage in the Delaware Basin. Some of this acreage, and a portion of the production, included properties identified at the time of our December 2016 equity and notes offerings. These transactions were pending at the time of those offerings and closed subsequent to December 31, 2016, bringing our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres, almost all of which was located in the Delaware Basin. We have incurred capital expenditures of approximately $111 million since January 1, 2017 to acquire leasehold and mineral interests and the related production. +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the next five years. We continue to operate the Delaware Midstream Assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will continue to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +4 +Table of Contents +Principal Areas of Interest — Exploration and Production Segment +Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana and East Texas. During 2016 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our asset areas by exploring for more conventional targets as well, although at December 31, 2016 , essentially all of our efforts were focused on unconventional plays. +At December 31, 2016 , our principal areas of interest consisted of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2016 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +163,703 +94,312 +312 +135.1 +4,162 +1,660.2 +79,388 +35.5 +15,941 +South Texas: +Eagle Ford (5) +30,669 +27,777 +136 +115.1 +249 +214.2 +13,298 +55.0 +4,952 +Northwest Louisiana/East Texas: +Haynesville +20,105 +12,452 +204 +19.8 +431 +103.0 +12,414 +61.1 +6,517 +Cotton Valley (6) +21,614 +19,071 +81 +54.2 +71 +50.1 +652 +100.0 +403 +Area Total (7) +26,062 +23,278 +285 +74.0 +502 +153.1 +13,066 +63.0 +6,920 +Total (8) +220,434 +145,367 +733 +324.2 +4,913 +2,027.5 +105,752 +41.4 +27,813 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2016 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2016 , these engineered drilling locations included only 163 gross (90.3 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Delaware and Strawn formations in the Delaware Basin, 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 12 gross (4.0 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2016 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +(8) +During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho. +We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation, Cimarex Energy Company, BHP Billiton, Mewbourne Oil Company, Occidental Petroleum Corporation, Chevron Corporation and others. At December 31, 2016 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2016 , we also were the operator for approximately 93% of our Eagle Ford acreage and +5 +Table of Contents +approximately 65% of our Haynesville acreage, including approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +As noted above in “—2016 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2016 , and as a result, at December 31, 2016 , our total acreage position in Southeast New Mexico and West Texas was approximately 163,700 gross ( 94,300 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,700 gross (20,400 net) acres in our Ranger asset area in Lea County, 48,000 gross (17,000 net) acres in our Arrowhead asset area in Eddy County, 25,100 gross (16,500 net) acres in our Rustler Breaks asset area in Eddy County, 13,500 gross (8,400 net) acres in our Wolf and Jackson Trust asset areas in Loving County and 42,900 gross (30,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2016 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2016 , our acreage position in the Delaware Basin was approximately 36% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical Strawn well, our acreage position in the Delaware Basin was approximately 47% held by existing production at December 31, 2016. +During the year ended December 31, 2016 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin, including 40 gross (35.6 net) operated wells and 15 gross (1.4 net) non-operated wells, throughout our various asset areas. At December 31, 2016 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2016 . Our average daily oil equivalent production from the Delaware Basin increased approximately 145% (2.5-fold) to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 , as compared to 6,518 BOE per day ( 26% of total oil equivalent production), including 4,648 Bbl of oil per day ( 38% of total oil production) and 11.2 +6 +Table of Contents +MMcf of natural gas per day ( 15% of total natural gas production), in 2015 . In addition, our average daily oil equivalent production from the Delaware Basin also grew approximately 138% (2.4-fold) from 8,720 BOE per day in the fourth quarter of 2015 to 20,670 BOE per day in the fourth quarter of 2016 . +At December 31, 2016 , approximately 75% of our estimated total proved oil and natural gas reserves, or 79.4 million BOE, was attributable to the Delaware Basin, including approximately 46.9 million Bbl of oil and 195.1 Bcf of natural gas, a 68% increase, as compared to 47.1 million BOE for the year ended December 31, 2015 . Our Delaware Basin proved reserves at December 31, 2016 comprised approximately 82% of our proved oil reserves and 67% of our proved natural gas reserves, as compared to approximately 69% of our proved oil reserves and 40% of our proved natural gas reserves at December 31, 2015 . +At December 31, 2016 , we had identified 4,162 gross ( 1,660.2 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Avalon and Delaware formations and the deeper Strawn formation. These locations include 2,546 gross (1,478.1 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2016 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our upcoming horizontal test of the Wolfcamp D in 2017). Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2016 , these potential future drilling locations included only 163 gross (90.3 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Delaware and Strawn formations, to which we have assigned proved undeveloped reserves. +At December 31, 2016 and February 22, 2017 , we were operating four drilling rigs in the Delaware Basin—two in the Rustler Breaks asset area, one in the Wolf/Jackson Trust asset areas and one in the Ranger/Arrowhead and Twin Lakes asset areas. We intend to operate four rigs in these asset areas throughout the remainder of 2017, and we expect to add a fifth drilling rig in the Delaware Basin beginning early in the second quarter of 2017. Thereafter, we expect to operate this fifth drilling rig in the Rustler Breaks asset area throughout the remainder of 2017. We are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated substantially all of our 2017 estimated capital expenditure budget to our drilling and completion program and midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. +Rustler Breaks Asset Area +We made significant progress delineating, developing and testing our acreage position in the Rustler Breaks asset area in 2016. The ten Wolfcamp A-XY wells and two Wolfcamp B (Middle) wells completed and placed on production in the Rustler Breaks asset area in 2016 were consistent with or better than the best Wolfcamp A-XY wells and Wolfcamp B (Middle) wells drilled by us in this asset area to date. The Paul 25-24S-28E RB #221H well tested at the highest 24-hour initial potential flow rate of any Wolfcamp A-XY well we have drilled at Rustler Breaks—1,701 BOE per day (74% oil)—and early performance from this well indicates that it may be the best Wolfcamp A-XY well drilled to date at Rustler Breaks. During 2016, we tested our first five wells drilled in the deepest bench of the Wolfcamp B (Blair) at Rustler Breaks. This is the third bench of the Wolfcamp B we have successfully tested at Rustler Breaks. These three target benches of the Wolfcamp B occur starting approximately 300 feet into the 1,000-foot thick Wolfcamp B interval at Rustler Breaks and are each about 200 to 250 feet apart vertically. +The 24-hour initial potential flow rates from the five Wolfcamp B (Blair) wells we completed and placed on production in 2016—the Dr. Scrivner Federal 01-24S-28E RB #228H, the Jimmy Kone 05-24S-28E RB #228H, the Janie Conner 13-24S-28E RB #221H, the Anne Com 15-24S-28E RB #221H (Anne Com #221H) and the Tiger 14-24S-28E RB #227H—were the five highest 24-hour test results we have reported in the Delaware Basin to date (with the exception of the three Mallon wells discussed below) at 2,570 BOE per day, 2,438 BOE per day, 2,384 BOE per day, 2,364 BOE per day and 1,812 BOE per day, respectively, at about 35% oil. These 24-hour initial potential test results compare favorably to those from other wells completed in the Wolfcamp B (Middle), the Tiger 14-24S-28E RB #224H and Janie Conner 13-24S-28E RB #224H wells, which had 24-hour initial potential rates of 1,533 BOE per day (43% oil) and 1,703 BOE per day (59% oil), respectively. The initial oil volumes from these lower Wolfcamp B (Blair) completions were reasonably comparable to or better than those in the Wolfcamp B (Middle), while the initial natural gas volumes were higher. In some instances, the oil rates tested on the lower Wolfcamp B (Blair) wells were close to those tested on the Wolfcamp A-XY wells. +7 +Table of Contents +In the Rustler Breaks asset area in 2016 , we reduced our average drilling time from spud to total depth in the Wolfcamp A-XY by approximately 31% and 16%, as compared to 2014 and 2015, respectively, and in the Wolfcamp B by approximately 50% and 35%, respectively. Our fastest-drilled Wolfcamp A-XY well, the B. Banker 33-23S-28E #226H well, was drilled in 12.5 days from spud to a total depth of 14,350 feet, a decrease of almost 50% from the average drilling time in late 2014, and our fastest-drilled Wolfcamp B well, the Anne Com #221H, was drilled in 17.4 days from spud to a total depth of 15,364 feet, a decrease of 58% from the average drilling time in 2014. These drilling times of 12.5 and 17.4 days were faster than our 2016 drilling objectives of 14 days for the Wolfcamp A-XY and 18 days for the Wolfcamp B, respectively, from spud to total depth. We delivered faster drilling times as a result of our increased knowledge of the geology and our experience with drilling in the Rustler Breaks asset area, as well as improvements in drilling the curve between the vertical and horizontal portions of these wells and continued applications of improved drill bit and bottomhole assembly technologies. +Due in part to these improvements in drilling times, continued innovation by our technical staff and lower oilfield services costs, the costs associated with recent Wolfcamp A-XY and Wolfcamp B wells at Rustler Breaks continued to decline throughout 2016. We were able to drill, complete and equip several wells in the Wolfcamp A-XY for just under $5 million each and in the Wolfcamp B for approximately $5.7 million each in mid-to-late 2016. +All of the Wolfcamp A-XY wells completed and placed on production in the Rustler Breaks asset area in 2016 were stimulated using our Generation 3 Wolfcamp stimulation treatment design, consisting of approximately 40 Bbl of fracturing fluid and 3,000 pounds of primarily 30/50 white sand per completed lateral foot. Similarly, we pumped this Generation 3 Wolfcamp stimulation treatment design in our Wolfcamp B (Blair) completions in the third and fourth quarters of 2016. Prior to this, most of our Wolfcamp A and B completions in the Rustler Breaks asset area used approximately 30 to 40 Bbl of fracturing fluid and 2,000 pounds of primarily 30/50 white sand per completed lateral foot. We also continued to pump diverting agents in most of our stimulation treatments in the Rustler Breaks asset area during the third and fourth quarters of 2016. +Wolf and Jackson Trust Asset Areas +Operational efficiencies continued to improve in the Wolf asset area as well. In 2016 , we reduced our average drilling time from spud to total depth in the Wolfcamp A-X and A-Y by approximately 52% and 10% as compared to 2014 and 2015, respectively, and in the Second Bone Spring by approximately 42% as compared to our first well drilled in the Second Bone Spring in 2015. Our fastest-drilled Wolfcamp A well, the Dorothy White 82-TTT-B33 #203H well, was drilled in 17.3 days from spud to a total depth of 15,550 feet, a decrease of 61% from the 2014 average drilling time and faster than our 2016 Wolfcamp A drilling objective of 18 days from spud to total depth in the Wolf asset area. The Barnett 90-TTT-B01 WF #124H (Barnett #124H) well, a Second Bone Spring test, was drilled in approximately 11.5 days (11.2 days normalized to a 5,000-foot lateral length) from spud to total depth, with drilling times being faster than our 2016 year-end drilling target of 13 days for Second Bone Spring wells. In the Barnett #124H and subsequent Second Bone Spring wells drilled in 2016, our drilling engineers were also able to eliminate a second intermediate casing string typically used when drilling the Second Bone Spring in this area. Not only did eliminating this casing string save approximately $650,000 in well costs on each Second Bone Spring well drilled in 2016, but it also provided for larger casing to be set through the lateral, thereby reducing hydraulic horsepower costs during fracturing operations and enhancing the number of artificial lift options available in the future. Total costs to drill, complete and equip Second Bone Spring wells in the Wolf asset area were just over $4 million in mid-to-late 2016. +Well costs associated with recent Wolfcamp A-X and A-Y wells drilled and completed in the Wolf asset area also continued to decline. Costs to drill, complete and equip Wolfcamp A wells ranged between $5 and $6 million, with a number of these wells at or below $5.5 million in mid-to-late 2016. As in the Rustler Breaks asset area, we attribute these cost savings to the innovation and use of new technologies by our drilling, completions and production teams, as well as lower oilfield services costs. +Our Second Bone Spring completions in 2016 represented significant improvements over our initial Second Bone Spring well drilled in the Wolf asset area in 2015. We attribute this improvement in well performance to the increased stimulation treatments pumped in 2016. The 2016 wells were completed using approximately 40 Bbl of fracturing fluid and 2,000 pounds of primarily 20/40 sand per completed lateral foot, compared to our initial Second Bone Spring completion in the Wolf asset area, which used only 20 Bbl of fracturing fluid and about 1,300 pounds of primarily 30/50 sand per completed lateral foot. In particular, we were pleased with the test results observed from the Johnson 44-02S-B53 WF #121H well, which had the highest test rate achieved from any Second Bone Spring well we have drilled to date of 1,167 BOE per day (58% oil). +We did not complete and place on production any new wells in our Jackson Trust asset area in 2016, although we do have several wells planned in our Jackson Trust asset area for 2017. +8 +Table of Contents +Ranger and Arrowhead Asset Areas +In the Ranger asset area in Lea County, New Mexico, we completed and placed on production the Mallon 27 Federal Com #1H, #2H and #3H wells, each of which are 7,300-foot laterals drilled and completed in the Third Bone Spring sand. These wells were the first operated wells we have drilled on the acreage acquired in our 2015 merger with Harvey E. Yates Company (“HEYCO” and, such merger, the “HEYCO Merger”). In aggregate, these three wells flowed 7,856 BOE per day (91% oil) in their 24-hour initial potential tests. Each well was completed with a 29-stage fracture treatment, including approximately 40 Bbl of fluid and 3,000 pounds of primarily 20/40 white sand per completed lateral foot. At December 31, 2016, these were the largest fracture treatments we have pumped in a Bone Spring completion. The Mallon wells were among the best wells we have drilled to date in the Delaware Basin, and these wells illustrate the potential of our northern Delaware Basin acreage position. +We did not conduct any operated drilling and completion activities in our Arrowhead asset area during 2016 , although we did participate in one new, non-operated well on our Arrowhead acreage during the first quarter of 2016. This well, the Yates Petroleum Corporation Baroque “BTQ” Federal Com #1H well, tested at flow rates averaging approximately 1,300 BOE per day (including approximately 1,100 Bbl of oil per day and 1.2 MMcf of natural gas per day) beginning in late March 2016. This well is located in the eastern portion of our Arrowhead asset area in Eddy County, New Mexico. We own a 9.5% working interest in this well, which provides yet another indication of the prospectivity of our northern Delaware Basin acreage. +Twin Lakes Asset Area +In our Twin Lakes asset area in northern Lea County, New Mexico, we drilled an initial data collection well, the Olivine State 5-16S-37E TL #1 (Olivine State #1), during the fourth quarter of 2015. This was a vertical pilot hole drilled for the purpose of collecting whole core and a detailed suite of geophysical logs to assist us in determining the landing target for our initial horizontal test of the Wolfcamp D interval at Twin Lakes. We collected about 400 feet of whole core throughout much of the Wolfcamp D interval, and our geoscience staff, along with third-party vendors, have conducted detailed description and analysis of the core data and well logs. The Olivine State #1 was drilled through the Wolfcamp D and into and through the Strawn formation below. The Strawn interval at about 11,500 feet is a complex carbonate formation that has previously produced significant quantities of oil and natural gas in the Twin Lakes area. Upon drilling through the Strawn interval, our geoscience staff analyzed the well logs taken across the interval and determined that there was the potential for a Strawn test. As a result, the Olivine State #1 was perforated and completed in the Strawn interval with a small acid treatment during the first quarter of 2016. This well flowed 691 BOE per day (84% oil) during a 24-hour initial potential test, consisting of 579 Bbl of oil per day and 0.7 MMcf of natural gas per day, at a flowing surface pressure of 350 psi on a 32/64 inch choke. Given the positive results from this Strawn test, we elected to produce the Olivine State #1 rather than plug back, kick off and drill a horizontal Wolfcamp D test from this vertical wellbore as originally anticipated. We expect to drill a new horizontal well to test the Wolfcamp D interval beginning late in the first quarter of 2017. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2016 , our properties included approximately 30,700 gross ( 27,800 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. Approximately 85% of our Eagle Ford acreage was held by production at December 31, 2016 , and approximately 95% of our Eagle Ford acreage was either held by production at December 31, 2016 or not burdened by lease expirations before 2018 . +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2016 , although we did participate in the drilling and completion of two gross (less than 0.1 net) non-operated Eagle Ford shale wells that were turned to sales in 2016 . In fact, as of December 31, 2016, we had not drilled any operated wells in the Eagle Ford shale since early 2015, when we completed and placed on production 17 gross (17.0 net) operated Eagle Ford shale wells in the first four months of 2015. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 52% to 4,952 BOE per day, including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016 , as compared to 10,263 BOE per day, including 7,642 Bbl of oil per day and 15.7 MMcf of natural gas per day, during 2015 . For the year ended December 31, 2016 , 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2015 , approximately 41% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +9 +Table of Contents +At December 31, 2016 , approximately 13% of our estimated total proved oil and natural gas reserves, or 13.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.1 million Bbl of oil and 19.3 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 18% of our proved oil reserves and 7% of our proved natural gas reserves at December 31, 2016 , as compared to approximately 31% of our proved oil reserves and 12% of our proved natural gas reserves at December 31, 2015 . +At December 31, 2016 , we had identified 249 gross ( 214.2 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. Approximately 95% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2018 at December 31, 2016 . At December 31, 2016 , these 249 gross ( 214.2 net) identified drilling locations included only 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and Edwards formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2016 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations. +Northwest Louisiana and East Texas +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2016 , although we did participate in the drilling and completion of 15 gross (2.1 net) non-operated Haynesville shale wells that were turned to sales in 2016 . These wells included nine gross (1.9 net) Haynesville wells operated by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove acreage in southern Caddo Parish, Louisiana. These nine wells came on production at an average of 13.5 MMcf per day and were drilled and completed for an average of under $7 million. We do not plan to drill any operated Haynesville shale wells in 2017 . +At December 31, 2016 , we held approximately 26,100 gross ( 23,300 net) acres in Northwest Louisiana and East Texas, including 20,100 gross ( 12,500 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the 13,200 gross ( 6,400 net) acres that we consider to be in the core area of the Haynesville play. +For the year ended December 31, 2016 , approximately 25% of our average daily oil equivalent production, or 6,920 BOE per day, including 12 Bbl of oil per day and 41.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 50% of our daily natural gas production, but oil production from these properties comprised only about 0.1% of our daily oil production during 2016 , as compared to approximately 64% of our daily natural gas production and approximately 0.1% of our daily oil production during 2015 . During the year ended December 31, 2015 , approximately 33% of our average daily oil equivalent production, or 8,174 BOE per day, including 16 Bbl of oil per day and 48.9 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2016 , approximately 47% of our daily natural gas production, or 39.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.3 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2015 , approximately 61% of our daily natural gas production, or 46.4 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.6 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2016 , approximately 12% of our estimated total proved reserves, or 12.4 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 0.7 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +10 +Table of Contents +At December 31, 2016 , we had identified and engineered 431 gross ( 103.0 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.1 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 431 gross ( 103.0 net) locations identified for future drilling on our Haynesville acreage, 357 gross (50.1 net) locations have been identified within the 13,200 gross ( 6,400 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2016 , these potential future drilling locations included only 12 gross (4.0 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Haynesville and Middle Bossier Shales +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. +At December 31, 2016 , we had approximately 20,100 gross ( 12,500 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,200 gross ( 6,400 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,200 net acres are prospective for the Middle Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2016 . +Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,100 net acres. We have identified 25 gross (19.6 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parish, Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to just over 31%. +Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations +Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. +All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately 10,000 gross (9,800 net) acres at December 31, 2016 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We have identified 71 gross ( 50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove properties. We did not drill any of these locations in 2016 and do not plan to drill any of these locations in 2017 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale +11 +Table of Contents +wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. +We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other asset areas in Northwest Louisiana and East Texas. At December 31, 2016 , we held an estimated 11,600 gross (9,200 net) leasehold and mineral acres by existing production in these areas. +Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale +During the year ended December 31, 2016 , we released all of our leasehold interests in Southwest Wyoming and adjacent areas in Utah and Idaho, which were originally leased as a part of a natural gas shale exploration prospect targeting the Meade Peak shale. As a result, we held no leasehold interests in these areas at December 31, 2016 . +Midstream Segment +The midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a limited basis. Through the ownership and operation of these facilities, we improve our ability to manage costs and control the timing of bringing on new production, and we enhance the value received for our production. With the exception of a joint venture, which we controlled and which owned salt water disposal assets in Loving County, Texas, all of our midstream operations were wholly-owned by the Company at December 31, 2016 . In February 2017, we contributed our Delaware Midstream Assets to San Mateo. +Southeast New Mexico and West Texas — Delaware Basin +In late August 2016, we successfully completed and began operating the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico. The Black River Processing Plant has an inlet capacity of approximately 60 MMcf of natural gas per day, which is almost twice the size of the previous cryogenic processing plant we built in our Wolf asset area in Loving County, Texas (the “Wolf Processing Plant”) and subsequently sold to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Black River Processing Plant and associated gathering system was built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with priority one takeaway and processing services for our Rustler Breaks natural gas production. It may also provide additional income through the gathering and processing of third-party natural gas. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks. In addition, in late December 2016, we placed in service our initial salt water disposal well and associated salt water disposal facility and water gathering pipelines in our Rustler Breaks asset area. We disposed of over 800,000 Bbl of salt water during the well’s first two months of operation. +In our Wolf asset area in Loving County, Texas, we have oil, natural gas and salt water gathering systems that gather our oil, natural gas and water production and a small volume of third-party natural gas. We retained this three-pipeline system following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to EnLink in October 2015. The Loving County Processing System included the Wolf Processing Plant and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. We also retained our interest in commercial salt water disposal assets in Loving County. During 2016 , we disposed of approximately 10.2 million Bbl of salt water, including disposal of third-party salt water on a commercial basis. At February 22, 2017 , San Mateo had capacity to dispose of approximately 50,000 Bbl of salt water per day in the Wolf asset area. San Mateo is in the process of completing its third salt water disposal well and related disposal facility in the Wolf asset area, which is expected to be operational by the end of the first quarter of 2017 and which should increase the total salt water disposal capacity in the Wolf asset area to approximately 75,000 Bbl per day. +South Texas / Northwest Louisiana and East Texas +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases there and from third parties. We also have four non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo. +12 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2016, 2015 and 2014 . +Year Ended December 31, +2016 +2015 +2014 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +5,096 +4,492 +3,320 +Natural gas (Bcf) +30.5 +27.7 +15.3 +Total oil equivalent (MBOE) (1) +10,180 +9,109 +5,870 +Average daily production (BOE/d) (1) +27,813 +24,955 +16,082 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +41.19 +$ +45.27 +$ +87.37 +Oil, with realized derivatives (per Bbl) +$ +42.34 +$ +59.13 +$ +88.94 +Natural gas, without realized derivatives (per Mcf) +$ +2.66 +$ +2.71 +$ +5.08 +Natural gas, with realized derivatives (per Mcf) +$ +2.78 +$ +3.24 +$ +5.06 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +4.23 +$ +3.91 +(2) +$ +5.65 +Lease operating +$ +5.52 +$ +6.01 +(3) +$ +8.51 +(3) +Plant and other midstream services operating +$ +0.53 +$ +0.38 +$ +0.24 +Depletion, depreciation and amortization +$ +11.99 +$ +19.63 +$ +22.95 +General and administrative +$ +5.41 +$ +5.50 +$ +5.48 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(2) +$0.01 per BOE reclassified to third-party midstream services revenues due to our midstream business becoming a reportable segment in the third quarter of 2016. +(3) +$0.38 and $0.24 per BOE reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +3,805 +1,286 +— +5 +5,096 +Natural gas (Bcf) +12.2 +3.1 +14.3 +0.9 +30.5 +Total oil equivalent (MBOE) (3) +5,834 +1,813 +2,385 +148 +10,180 +Percentage of total annual net production +57.3 +% +17.8 +% +23.4 +% +1.5 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +10,395 +3,517 +— +12 +13,924 +Natural gas (MMcf/d) +33.3 +8.6 +39.1 +2.3 +83.3 +Total oil equivalent (BOE/d) +15,941 +4,952 +6,517 +403 +27,813 +Average Sales Prices (4) +Oil (per Bbl) +$ +41.76 +$ +39.49 +$ +— +$ +38.78 +$ +41.19 +Natural gas (per Mcf) +$ +3.15 +$ +3.11 +$ +2.17 +$ +2.27 +$ +2.66 +Total oil equivalent (per BOE) +$ +33.81 +$ +33.46 +$ +13.04 +$ +14.39 +$ +28.60 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +7.32 +$ +12.74 +$ +4.73 +$ +17.07 +$ +7.82 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +13 +Table of Contents +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +1,697 +2,789 +— +6 +4,492 +Natural gas (Bcf) +4.1 +5.7 +16.9 +1.0 +27.7 +Total oil equivalent (MBOE) (3) +2,379 +3,746 +2,822 +162 +9,109 +Percentage of total annual net production +26.1 +% +41.1 +% +31.0 +% +1.8 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +4,648 +7,642 +— +16 +12,306 +Natural gas (MMcf/d) +11.2 +15.7 +46.4 +2.6 +75.9 +Total oil equivalent (BOE/d) +6,518 +10,263 +7,731 +443 +24,955 +Average Sales Prices (4) +Oil (per Bbl) +$ +43.54 +$ +46.33 +$ +— +$ +43.68 +$ +45.27 +Natural gas (per Mcf) +$ +3.00 +$ +3.17 +$ +2.49 +$ +2.45 +$ +2.71 +Total oil equivalent (per BOE) +$ +36.21 +$ +39.35 +$ +14.97 +$ +15.69 +$ +30.56 +Production Costs (5) +Lease operating, transportation and processing (per BOE) (6) +$ +8.84 +$ +9.25 +$ +4.91 +$ +19.23 +$ +7.90 +_________________ +(1) +Includes one wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +(6) +Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2014 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +480 +2,834 +— +6 +3,320 +Natural gas (Bcf) +1.0 +6.0 +7.2 +1.1 +15.3 +Total oil equivalent (MBOE) (3) +653 +3,833 +1,201 +183 +5,870 +Percentage of total annual net production +11.1 +% +65.3 +% +20.5 +% +3.1 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +1,314 +7,764 +— +17 +9,095 +Natural gas (MMcf/d) +2.9 +16.4 +19.7 +2.9 +41.9 +Total oil equivalent (BOE/d) +1,790 +10,501 +3,290 +501 +16,082 +Average Sales Prices (4) +Oil (per Bbl) +$ +80.16 +$ +88.58 +$ +— +$ +91.24 +$ +87.37 +Natural gas (per Mcf) +$ +4.75 +$ +6.72 +$ +3.87 +$ +4.30 +$ +5.08 +Total oil equivalent (per BOE) +$ +66.41 +$ +75.99 +$ +23.27 +$ +27.92 +$ +62.64 +Production Costs (5) +Lease operating, transportation and processing (per BOE) (6) +$ +13.08 +$ +10.34 +$ +8.13 +$ +17.58 +$ +10.29 +_________________ +(1) +Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +(6) +Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016. +Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have not drilled any new operated wells since the second quarter of 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, as compared to 24,955 BOE per day for the year ended December 31, 2015 . Our average daily oil production for the year ended December 31, 2016 was 13,924 Bbl of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year ended December 31, 2015 . Our average daily natural gas production for the year ended December 31, 2016 was 83.3 MMcf of natural gas per day, an increase of 10% from 75.9 MMcf of natural gas per day for the year ended December 31, 2015 . +Our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 increased 55% from our total oil equivalent production of approximately 5.9 million BOE for the year ended December 31, 2014 . This increased production was primarily due to our delineation and development operations in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily oil equivalent production for the year ended December 31, 2015 was 24,955 BOE per day, as compared to 16,082 BOE per day for the year ended December 31, 2014 . Our average daily oil production for the year ended December 31, 2015 was 12,306 Bbl of oil per day, an increase of 35% from 9,095 Bbl of oil per day for the year ended December 31, 2014 . Our average daily natural gas production for the year ended December 31, 2015 was 75.9 MMcf of natural gas per day, an increase of 81% from 41.9 MMcf of natural gas per day for the year ended December 31, 2014 . +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2016 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 72% in all wells that we operated at December 31, 2016. For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +261 +116.0 +51 +19.1 +312 +135.1 +South Texas: +Eagle Ford (2) +132 +111.1 +4 +4.0 +136 +115.1 +Northwest Louisiana/East Texas: +Haynesville +— +— +204 +19.8 +204 +19.8 +Cotton Valley (3) +2 +2.0 +79 +52.2 +81 +54.2 +Area Total +2 +2.0 +283 +72.0 +285 +74.0 +Total +395 +229.1 +338 +95.1 +733 +324.2 +__________________ +(1) +Includes 176 gross (50.5 net) wells acquired in February 2015 as part of the HEYCO Merger. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2016, 2015 and 2014 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +16 +Table of Contents +At December 31, (1) +2016 +2015 +2014 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +56,977 +45,644 +24,184 +Natural Gas (Bcf) (3) +292.6 +236.9 +267.1 +Total (MBOE) (4) +105,752 +85,127 +68,693 +Estimated proved developed reserves: +Oil (MBbl) +22,604 +17,129 +14,053 +Natural Gas (Bcf) (3) +126.8 +101.4 +102.8 +Total (MBOE) (4) +43,731 +34,037 +31,185 +Percent developed +41.4 +% +40.0 +% +45.4 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +34,373 +28,515 +10,131 +Natural Gas (Bcf) (3) +165.9 +135.5 +164.3 +Total (MBOE) (4) +62,021 +51,090 +37,508 +Standardized Measure (5) (in millions) +$ +575.0 +$ +529.2 +$ +913.3 +PV-10 (6) (in millions) +$ +581.5 +$ +541.6 +$ +1,043.4 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, and for the 12 months ended December 31, 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. +(3) +Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated properties in the Haynesville shale. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classified proved undeveloped reserves from our total proved reserves in 2016. +(5) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(6) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2016, 2015 and 2014 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2016, 2015 and 2014 were, in millions, $6.5 , $12.4 and $130.1 , respectively. +Our estimated total proved oil and natural gas reserves increase d 24% from 85.1 million BOE at December 31, 2015 to 105.8 million BOE at December 31, 2016 . We added 42.0 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2016, approximately 4.1 times our 2016 annual production of 10.2 million BOE. Our proved oil reserves grew 25% from approximately 45.6 million Bbl at December 31, 2015 to approximately 57.0 million Bbl at December 31, 2016 . Our proved natural gas reserves increase d 24% from 236.9 Bcf at December 31, 2015 to 292.6 Bcf at December 31, 2016 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2016. We incurred approximately 11.2 million BOE in net downward revisions to our proved reserves during 2016 as a result of the reclassification of certain proved undeveloped reserves to contingent resources, primarily due to the lower oil and natural gas prices used to estimate proved reserves at December 31, 2016, as compared to December 31, 2015. These contingent resources may be reclassified to proved undeveloped reserves in future periods should the oil and natural gas prices used to estimate proved oil and natural gas reserves improve from the prices at December 31, 2016. Our proved reserves to production ratio at December 31, 2016 was 10.4, an increase of 11% from 9.4 at December 31, 2015. +17 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increase d 9% from $529.2 million at December 31, 2015 to $575.0 million at December 31, 2016 . The PV-10 of our total proved oil and natural gas reserves increase d 7% from $541.6 million at December 31, 2015 to $581.5 million at December 31, 2016 . The increase in our Standardized Measure and PV-10 are primarily a result of our delineation and development operations in the Delaware Basin during 2016, which was partially impacted by the lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2016 , as compared to December 31, 2015 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2016 were $39.25 per Bbl and $2.48 per MMBtu, a decrease of 17% and 4% , respectively, as compared to average oil and natural gas prices of $46.79 per Bbl and $2.59 per MMBtu used to estimate proved reserves at December 31, 2015 . Our total proved reserves were made up of approximately 54% oil and 46% natural gas at December 31, 2016 and December 31, 2015 . +Our proved developed oil and natural gas reserves increase d 28% from 34.0 million BOE at December 31, 2015 to 43.7 million BOE at December 31, 2016 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 32% from 17.1 million Bbl at December 31, 2015 to 22.6 million Bbl at December 31, 2016 . Our proved developed natural gas reserves increase d 25% from 101.4 Bcf at December 31, 2015 to 126.8 Bcf at December 31, 2016 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2016 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2015 +34,037 +Extensions and discoveries +12,583 +Revisions of prior estimates +408 +Production +(10,180 +) +Conversion of proved undeveloped to proved developed +6,883 +As of December 31, 2016 +43,731 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d from 51.1 million BOE at December 31, 2015 to 62.0 million BOE at December 31, 2016 . Our proved undeveloped oil and natural gas reserves increased from 28.5 million Bbl and 135.5 Bcf, respectively, at December 31, 2015 to 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2016 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2016 within five years of booking these reserves. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2016 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2015 +51,090 +Extensions and discoveries +29,408 +Revisions of prior estimates +(11,594 +) +Conversion of proved undeveloped to proved developed +(6,883 +) +As of December 31, 2016 +62,021 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +The following table sets forth, since 2013, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2013 +2,944 +8.3 +4,334 +$ +115,699 +2014 +3,780 +44.7 +11,223 +201,950 +2015 +2,854 +23.4 +6,747 +104,989 +2016 +4,705 +13.1 +6,883 +94,579 +Total +14,283 +89.5 +29,187 +$ +517,217 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2016 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +46,873 +195.1 +79,388 +$ +446.0 +$ +451.0 +South Texas: +Eagle Ford (5) +10,066 +19.3 +13,298 +85.6 +86.6 +Northwest Louisiana/East Texas: +Haynesville +— +74.5 +12,414 +41.5 +42.0 +Cotton Valley (6) +38 +3.7 +652 +1.9 +1.9 +Area Total +38 +78.2 +13,066 +43.4 +43.9 +Total +56,977 +292.6 +105,752 +$ +575.0 +$ +581.5 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2016 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2016 were approximately $ 6.5 million . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational +19 +Table of Contents +methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 39 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2016 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +79,087 +33,699 +84,616 +60,613 +163,703 +94,312 +South Texas: +Eagle Ford +26,402 +23,682 +4,267 +4,095 +30,669 +27,777 +Northwest Louisiana/East Texas: +Haynesville +16,739 +9,088 +3,366 +3,364 +20,105 +12,452 +Cotton Valley +18,108 +16,078 +3,506 +2,993 +21,614 +19,071 +Area Total (1) +22,030 +19,761 +4,032 +3,517 +26,062 +23,278 +Total (2) +127,519 +77,142 +92,915 +68,225 +220,434 +145,367 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +(2) +During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2016 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2020 and beyond represents an immaterial amount of our overall undeveloped acreage. +20 +Table of Contents +Acres +Acres +Acres +Expiring 2017 +Expiring 2018 +Expiring 2019 +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +17,604 +7,987 +39,704 +25,294 +15,404 +9,086 +South Texas: +Eagle Ford +1,435 +1,375 +896 +753 +204 +156 +Northwest Louisiana/East Texas: +Haynesville +— +— +— +— +326 +324 +Cotton Valley +— +— +— +— +— +— +Area Total (2) +— +— +— +— +326 +324 +Total +19,039 +9,362 +40,600 +26,047 +15,934 +9,566 +__________________ +(1) +Approximately 54% of the acreage expiring in the next three years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes asset area in 2017 through our 2017 drilling activities or by paying an additional lease bonus, where applicable. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2016 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2016, 2015 and 2014 . +Year Ended December 31, +2016 +2015 +2014 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +44 +23.5 +53 +26.7 +89 +39.9 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +28 +15.6 +28 +17.5 +12 +10.6 +Dry +— +— +— +— +— +— +Total Wells +Productive +72 +39.1 +81 +44.2 +101 +50.5 +Dry +— +— +— +— +— +— +Marketing and Customers +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +21 +Table of Contents +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are based on various pipeline indices less any associated fees. When there is an opportunity to do so, we may have our natural gas processed at our or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the years ended December 31, 2016, 2015 and 2014 , we had three significant purchasers that accounted for approximately 48% , 59% and 68% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +22 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions, as well as drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering, processing and compression opportunities, as well as salt water disposal activities in the areas in which we operate. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated, and we can give no assurance that the current less stringent regulatory approach of FERC will continue. +23 +Table of Contents +In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil gathering facilities are also exempt from FERC’s jurisdiction under the Interstate Commerce Act. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and that the crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. +The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, as amended. In recent years, pursuant to these laws and, in addition, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking (NPRM) that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but has yet to publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +24 +Table of Contents +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management, or the BLM, with respect to federal acreage). +Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have also been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is +25 +Table of Contents +possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the Environmental Protection Agency, or the EPA, has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2016 , we owned and operated twelve underground injection wells and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and +26 +Table of Contents +operation of underground injection wells. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation +27 +Table of Contents +requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2016 , we had 165 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, land, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Compensation Committee, Corporate Governance Committee, Executive Committee and Nominating Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. \ No newline at end of file diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/item13.txt b/raw/filings/0001520006/2016/0001520006-17-000074/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..75bc618aa33b3508d38f224b21bc771760b75f7a --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. \ No newline at end of file diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/item9a.txt b/raw/filings/0001520006/2016/0001520006-17-000074/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..5abe5ae9ac582d2303e29a9a8da0372bfbf19636 --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/item9a.txt @@ -0,0 +1,29 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in +77 +Table of Contents +the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2016 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2016 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +78 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Shareholders +Matador Resources Company: +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2016 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2016 , 2015 and 2014, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016 , and our report dated March 1, 2017 expressed an unqualified opinion on those consolidated financial statements. +/s/ KPMG LLP +Dallas, Texas +March 1, 2017 +79 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/rp_note.txt b/raw/filings/0001520006/2016/0001520006-17-000074/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..4c997a468b6f8fde9e286560a11234fe199cfd5f --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/rp_note.txt @@ -0,0 +1,2 @@ +NOTE 16 — RELATED PARTY TRANSACTIONS +In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2016 , the Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. \ No newline at end of file diff --git a/raw/filings/0001520006/2016/0001520006-17-000074/rpt_disclosure.txt b/raw/filings/0001520006/2016/0001520006-17-000074/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..9aa8b65e318ecfc8b860ad8484b9d2dd0cd9d463 --- /dev/null +++ b/raw/filings/0001520006/2016/0001520006-17-000074/rpt_disclosure.txt @@ -0,0 +1,109 @@ +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2016 there was not, nor was there proposed as of December 31, 2016, any transaction or series of +similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the +immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive +Compensation — Compensation Discussion and Analysis” above. +HEYCO Joint Ventures +In June 2015, the Company entered into two joint ventures (the “Joint Ventures”) to develop certain leasehold interests held by +certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of Harvey E. Yates Company. The HEYCO Affiliates are owned by George M. Yates, who was appointed to the Board on April 28, 2015 in +accordance with the terms of the HEYCO Merger, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held +by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of +December 31, 2016, the Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s contributions are being used to fund capital expenditures associated with the interests owned by the Joint +Ventures as well as to fund acquisitions by the Joint Ventures of other non-operated acreage opportunities. +The Audit Committee reviewed the terms of the Joint Ventures for potential conflicts of interest under the Company’s related party transaction policy, effective October 12, 2011 (the +“Related Party Transaction Policy”), and, after being fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Joint Ventures, determined that the Joint Ventures were fair to the +Company and recommended the Joint Ventures to the full Board for approval and ratification. The Board subsequently approved and ratified the Joint Ventures. +In addition, in light of Mr. Yates’ ongoing services to HEYCO Energy Group, Inc., the Board, in accordance with Texas corporate law, adopted resolutions which renounce and provide for a waiver +of certain corporate opportunities with respect to Mr. Yates. As a result, Mr. Yates will have no fiduciary duty to present certain corporate opportunities related to Mr. Yates’ existing oil and gas holdings and/or in areas where +Matador does not currently operate. +Working Interest Acquisition +A sibling of Mr. Yates is affiliated with and controls Jalapeno Corporation (“Jalapeno”). In an arms-length transaction +completed in 2016, the Company acquired Jalapeno’s working interest in certain oil and natural gas properties operated by the Company (the “Working Interest Acquisition”). The Company paid Jalapeno approximately $3.6 million for +the Working Interest Acquisition. +The Audit Committee reviewed the terms of the Working Interest Acquisition for potential +conflicts of interest under the Related Party Transaction Policy and, after being fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Working Interest Acquisition, determined that the +Working Interest Acquisition was fair to the Company and recommended the Working Interest Acquisition to the full Board for approval and ratification. The Board subsequently approved and ratified the Working Interest Acquisition. +Term Assignment +A +sibling of Mr. Yates is affiliated with and controls Yates Energy Corporation (“Yates Energy”). In an arms-length transaction completed in 2016, the Company acquired a term assignment of Yates Energy’s working +60 +Table of Contents +interest in certain oil and natural gas properties operated by the Company (the “Term Assignment”). The Company paid Yates Energy approximately $170,000 for the Term Assignment. +The Audit Committee reviewed the terms of the Term Assignment for potential conflicts of interest under the Related Party +Transaction Policy and, after being fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Term Assignment, determined that the Term Assignment was fair to the Company and recommended the Term +Assignment to the full Board for approval and ratification. The Board subsequently approved and ratified the Term Assignment. +Working +Interest and Overriding Royalty Interest Owners +Certain HEYCO Affiliates or entities controlled by members of +Mr. Yates’ family (collectively, the “Yates Entities”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As +working interest owners, the Yates Entities are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the +Yates Entities are entitled to receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2016, revenues, net of costs, received by the Yates Entities in their capacities as +working interest owners or overriding royalty interest owners were approximately $883,000 (the “Yates Net Revenue Payments”). +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2016, our joint interest billings to the Yates +Entities attributable to their share of costs were approximately $1.1 million (the “Yates Billings”). This represents less than 1% of our total joint interest billings during 2016. As a result of this ownership by the Yates Entities, +from time to time, we will be in a net receivable or net payable position with the Yates Entities. We do not consider any net receivables from these parties to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Yates Entities for potential +conflicts of interest under the Related Party Transaction Policy, and, after being fully informed as to Mr. Yates’ relationship and interest in such transactions and all other material facts related to the Yates Net Revenue Payments and +Yates Billings, determined that such transactions and the Yates Net Revenue Payments and Yates Billings were fair to the Company and recommended such transactions and the Yates Net Revenue Payments and Yates Billings to the full Board for approval +and ratification. The Board subsequently approved and ratified the transactions and the Yates Net Revenue Payments and Yates Billings. +Certain Employment Relationships +Billy E. Goodwin, Senior Vice President — Operations, was appointed as an executive officer of the Company in connection with his February 2016 promotion to his present role. Two of +Mr. Goodwin’s adult children are employees of the Company and each earned in 2016, and are expected to be compensated in 2017, between $120,000 and $500,000. One of Mr. Goodwin’s children has a bachelor’s degree in petroleum +engineering from the University of Tulsa and over seven years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other child has a bachelor’s +degree in energy management from the University of Tulsa and a bachelor’s degree in general business and management from Oklahoma State University. He also has over seven years of industry experience, including as a drilling fluids engineer for +a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangements for potential conflicts of interest under the Company’s +Related Party Transaction Policy and, after being fully informed as to the employment arrangements and historical and anticipated compensation of Mr. Goodwin’s adult children, and all other material facts related to the relationship, +determined that the employment arrangements were fair to the Company and recommended the employment arrangements to +61 +Table of Contents +the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s +sister-in-law is an employee of the Company and earned in 2016, and is expected to be compensated in 2017 between $120,000 and $200,000. Mr. Baribault’s +sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist University Legal Assistants Program. She has over 35 years of experience as a legal assistant. The Audit +Committee reviewed the terms of the employment arrangements for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being fully informed as to the employment arrangements and historical and +anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement +was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of Joseph Wm. Foran, Chairman and CEO, is an employee of the Company and is expected to be compensated in 2017 between +$120,000 and $200,000. Mr. Foran’s child has a bachelor’s degree in human resources development and a master’s degree in human resources management, both from Texas A&M University. She has more than six years of industry +experience, including with another publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Party Transaction Policy +and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Foran’s adult child, and all other material facts related to the relationship, determined that the employment arrangement +was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +Procedures for Approval of Related Party Transactions +Pursuant to the Related Party Transaction Policy, a “Related Party Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any +indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, involving a Related Party (as defined below) and in which we are a participant, other than: +• +a transaction involving compensation of directors; +• +a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, change in control provision or +agreement or a special supplemental benefit for an executive officer; +• +a transaction available to all employees generally or to all salaried employees generally; +• +a transaction with a Related Party involving less than $120,000; +• +a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that +class receive the same benefit on a pro rata basis; or +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of +services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. +“Related Party” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or nominees for directors; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, +son-in-law, daughter-in-law, +62 +Table of Contents +brother-in-law or sister-in-law of +a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• +any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general +partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Party Transaction Policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or disapproval of the Related Party +Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all material facts of the Related Party +Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be disclosed in our filings with the SEC +and/or our website in accordance with applicable laws, rules and regulations. +63 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/filing.txt b/raw/filings/0001520006/2017/0001520006-18-000053/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..d035370ad6441948b9242cb059f3d83230cfce71 --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/filing.txt @@ -0,0 +1,7701 @@ +10-K +1 +a20171231mtdr10-k.htm +10-K +Document +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2017 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission file number 001-34574 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas +27-4662601 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 +Dallas, Texas 75240 +75240 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: (972) 371-5200 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ý No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +ý +Accelerated filer +¨ +Non-accelerated filer +¨ +(Do not check if a smaller reporting company) +Smaller reporting company +¨ +Emerging growth company +¨ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ¨ No ý +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,910,451,565 . +As of February 21, 2018 , there were 109,248,747 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2018 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +29 +I TEM 1B. +Unresolved Staff Comments +53 +I TEM 2. +Properties +53 +I TEM 3. +Legal Proceedings +53 +I TEM 4. +Mine Safety Disclosures +53 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +54 +I TEM 6. +Selected Financial Data +57 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +59 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +78 +I TEM 8. +Financial Statements and Supplementary Data +79 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +80 +I TEM 9A. +Controls and Procedures +80 +I TEM 9B. +Other Information +83 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +83 +I TEM 11. +Executive Compensation +83 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +83 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +83 +I TEM 14. +Principal Accounting Fees and Services +83 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +84 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, the sufficiency of our cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission, or the SEC, all of which are difficult to predict. Forward-looking statements may include statements about: +• +our business strategy; +• +our reserves; +• +our technology; +• +our cash flows and liquidity; +• +our financial strategy, budget, projections and operating results; +• +our oil and natural gas realized prices; +• +the timing and amount of future production of oil and natural gas; +• +the availability of drilling and production equipment; +• +the availability of oil field labor; +• +the amount, nature and timing of capital expenditures, including future exploration and development costs; +• +the availability and terms of capital; +• +our drilling of wells; +• +our ability to negotiate and consummate acquisition and divestiture opportunities; +• +government regulation and taxation of the oil and natural gas industry; +• +our marketing of oil and natural gas; +• +our exploitation projects or property acquisitions; +• +the integration of acquisitions with our business; +• +our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the expansion of our Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; +• +the ability of our midstream joint venture to attract third-party volumes; +• +our costs of exploiting and developing our properties and conducting other operations; +• +general economic conditions; +• +competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• +the effectiveness of our risk management and hedging activities; +• +environmental liabilities; +• +counterparty credit risk; +• +developments in oil-producing and natural gas-producing countries; +• +our future operating results; +• +estimated future reserves and the present value thereof; and +• +our plans, objectives, expectations and intentions contained in this Annual Report that are not historical. +1 +Table of Contents +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2017 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also continued to increase our leasehold position in the Delaware Basin. In addition, we concluded several important transactions in 2017 , including the formation of San Mateo in February 2017, the October 2017 public offering of 8,000,000 shares of our +2 +Table of Contents +common stock and multiple increases in the borrowing base under our Credit Agreement (as defined below). These transactions increased our operational flexibility and opportunities and further strengthened our balance sheet. +For information about our segment reporting, see Note 17 to the consolidated financial statements in this Annual Report. +2017 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2017 , we achieved record oil, natural gas and average daily oil equivalent production. In 2017 , we produced 7.9 million Bbl of oil, an increase of 54% , as compared to 5.1 million Bbl of oil produced in 2016 . We also produced 38.2 Bcf of natural gas, an increase of 25% from 30.5 Bcf of natural gas produced in 2016 . Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, an increase of 40% , as compared to 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, for the year ended December 31, 2016 . The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2017 , but also to production from five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Oil production comprised 55% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2017 , as compared to 50% for the year ended December 31, 2016 . +Increased Oil and Oil Equivalent Reserves +At December 31, 2017 , our estimated total proved oil and natural gas reserves were 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, an increase of 44% from 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, at December 31, 2016 . The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 119% and 129% to $1.26 billion and $1.33 billion , respectively, at December 31, 2017 , from $575.0 million and $581.5 million , respectively, at December 31, 2016 , primarily as a result of our ongoing delineation and development drilling activities in the Delaware Basin. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 52% to 86.7 million Bbl at December 31, 2017 from 57.0 million Bbl at December 31, 2016 . Our proved natural gas reserves increased 35% to 396.2 Bcf at December 31, 2017 from 292.6 Bcf at December 31, 2016 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2017 . +At December 31, 2017 , proved developed reserves included 37.0 million Bbl of oil and 190.1 Bcf of natural gas, and proved undeveloped reserves included 49.8 million Bbl of oil and 206.1 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 45% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2017 . Proved developed reserves and proved oil reserves comprised 41% and 54% , respectively, of our total proved oil and natural gas reserves at December 31, 2016 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past four years, as we continue to apply what we learned from our Eagle Ford shale and Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2018. +3 +Table of Contents +We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin in 2017, including 65 gross (56.1 net) operated and 21 gross (3.5 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2017 . As a result, at December 31, 2017 , our total acreage position in the Delaware Basin had increased to approximately 199,600 gross ( 114,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been pleased with the aggregate performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our seven main asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 85% to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 MMcf of natural gas per day ( 66% of total natural gas production), in 2017 , as compared to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 . We expect our Delaware Basin production to increase throughout 2018 as we continue the delineation and development of these asset areas. +Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2017 included: +• +in our Rustler Breaks asset area, the extension of Wolfcamp A-XY operations to the northwest region of the asset area, the initial testing of the Wolfcamp A-Lower interval and the continued delineation and development of previously tested horizons; +• +in our Jackson Trust asset area, the results from the Totum E 18-TTT-C24 NL #211H well, whose 24-hour initial potential test result and subsequent well performance marked the best result we have achieved in the Wolfcamp A-Lower interval in either the Wolf or Jackson Trust asset areas; +• +in our Wolf asset area, a positive first test of the Wolfcamp B interval; +• +in our Ranger asset area, the continued success of the three wells drilled and completed in the Third Bone Spring formation on our Mallon leasehold, which were placed on gas lift during the third quarter of 2017 and have together produced over 1.1 million Bbl of oil in just over one year of production; +• +in our Twin Lakes asset area, a positive test of the Wolfcamp D formation from the D. Culbertson 26-15S-36E TL State #234H well, our first horizontal well in the Twin Lakes asset area; +• +in our Arrowhead asset area, the drilling and completion of our first operated wells, which further illustrated the potential of the Second Bone Spring and the Third Bone Spring in our northern Delaware Basin acreage position; +• +in our Antelope Ridge asset area, the drilling of our first two operated wells, the first of which was completed in early 2018 and was a positive test of the Wolfcamp A interval that we believe confirms the prospectivity of the Antelope Ridge asset area; and +• +the significant progress made in our midstream operations, including (i) the ongoing expansion of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”), (ii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas and (iii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks and Wolf asset areas, significantly increasing San Mateo’s salt water disposal capacity in these asset areas. +We also completed and began producing oil and natural gas from eight gross (5.8 net) wells in the Eagle Ford shale in South Texas in 2017 , including five gross (5.0 net) operated and three gross (0.8 net) non-operated wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017 , although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that began producing in 2017 . +Financing Arrangements +On October 10, 2017 , we completed a public offering of 8,000,000 shares of our common stock, receiving proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, leasehold and mineral acquisitions and general corporate purposes, including to fund a portion of our current and future capital expenditures. +4 +Table of Contents +Midstream Joint Venture +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo. Through January 31, 2018, we had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018 and may earn up to an additional $58.8 million in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo continues to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +2018 Recent Developments +On January 22, 2018, we announced a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains All American Pipeline, L.P. (“Plains”) to gather and transport crude oil for us and third-party customers in and around the Rustler Breaks asset area. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase our oil production in the Rustler Breaks and Wolf asset areas. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During 2017 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our asset areas by exploring for more conventional targets as well, although for the year ended December 31, 2017 , essentially all of our efforts were focused on unconventional plays. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2017 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +199,600 +114,000 +450 +211.5 +4,630 +1,957.7 +128,999 +40.6 +29,463 +South Texas: +Eagle Ford (5) +31,800 +29,000 +142 +119.8 +241 +208.5 +12,346 +72.2 +4,413 +Northwest Louisiana/East Texas: +Haynesville +19,600 +12,000 +217 +20.5 +413 +102.0 +10,106 +59.5 +4,697 +Cotton Valley (6) +21,100 +18,600 +81 +54.3 +71 +50.0 +1,320 +100.0 +363 +Area Total (7) +25,500 +22,800 +298 +74.8 +484 +152.0 +11,426 +64.1 +5,060 +Total +256,900 +165,800 +890 +406.1 +5,355 +2,318.2 +152,771 +44.9 +38,936 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2017 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2017 , these engineered drilling locations included only 261 gross (130.5 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations in the Delaware Basin, 12 gross (12.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and nine gross (3.3 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. +5 +Table of Contents +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Production volumes and proved reserves reported in two streams; oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2017 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2017 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2017 , we also were the operator for approximately 94% of our Eagle Ford acreage and approximately 64% of our Haynesville acreage, including approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by an affiliate of Chesapeake Energy Corporation. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +As noted above in “— 2017 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2017 , and as a result, at December 31, 2017 , our total acreage position in Southeast New Mexico and West Texas was approximately 199,600 gross ( 114,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 28,800 gross (15,500 net) acres in our Ranger asset area in Lea County, 56,600 gross (23,400 net) acres in our Arrowhead asset area in Eddy County, 41,000 gross (21,200 net) acres in our Rustler Breaks asset area in Eddy County, 12,000 gross (8,900 net) acres in our Antelope Ridge asset area in Lea County, 13,600 gross (9,400 net) acres in our Wolf and Jackson Trust asset areas in Loving County and 46,100 gross (34,400 net) acres in our Twin Lakes asset area in Lea County at December 31, 2017 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka +6 +Table of Contents +and Morrow formations. At December 31, 2017 , our acreage position in the Delaware Basin was approximately 45% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical and one horizontal well, our acreage position in the Delaware Basin was approximately 59% held by existing production at December 31, 2017 . +During the year ended December 31, 2017 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin, including 65 gross (56.1 net) operated wells and 21 gross (3.5 net) non-operated wells, throughout our various asset areas. At December 31, 2017 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2017 . Our average daily oil equivalent production from the Delaware Basin increased approximately 85% to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 MMcf of natural gas per day ( 66% of total natural gas production), in 2017 , as compared to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 . Our average daily oil equivalent production from the Delaware Basin also grew approximately 69% from 20,670 BOE per day in the fourth quarter of 2016 to 34,859 BOE per day in the fourth quarter of 2017 . +At December 31, 2017 , approximately 84% of our estimated total proved oil and natural gas reserves, or 129.0 million BOE, was attributable to the Delaware Basin, including approximately 77.5 million Bbl of oil and 308.9 Bcf of natural gas, a 62% increase, as compared to 79.4 million BOE for the year ended December 31, 2016 . Our Delaware Basin proved reserves at December 31, 2017 comprised approximately 89% of our proved oil reserves and 78% of our proved natural gas reserves, as compared to approximately 82% of our proved oil reserves and 67% of our proved natural gas reserves at December 31, 2016 . +At December 31, 2017 , we had identified 4,630 gross ( 1,957.7 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 2,954 gross (1,775.5 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2017 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our second anticipated operated horizontal test of the Wolfcamp D formation in 2018). Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing and that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible, at December 31, 2017, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2017 , these potential future drilling locations included only 261 gross (130.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, to which we have assigned proved undeveloped reserves. +At December 31, 2017 , we were operating six drilling rigs in the Delaware Basin, and we expect to operate those rigs in the Delaware Basin throughout 2018, including three rigs in the Rustler Breaks asset area, one rig in the Wolf/Jackson Trust asset areas, one rig in the Ranger/Arrowhead and Twin Lakes asset areas and one rig in the Antelope Ridge asset area. One of the three rigs operating in the Rustler Breaks asset area is also expected to drill at least two commercial salt water disposal wells in that area during 2018 for San Mateo. As a result, we expect that this rig will spend only approximately three-quarters of the year drilling oil and natural gas wells. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2018. We have allocated substantially all of our 2018 estimated capital expenditure budget to our drilling and completion program and midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. +7 +Table of Contents +Rustler Breaks Asset Area - Eddy County, New Mexico +We operated three drilling rigs in our Rustler Breaks asset area during most of 2017. We completed and turned to sales 53 gross (34.5 net) horizontal wells in the Rustler Breaks asset area in 2017, including 37 gross (32.4 net) operated and 16 gross (2.1 net) non-operated wells. Most of these wells were completed in the Wolfcamp A-XY or Wolfcamp B-Blair intervals, and the well results achieved were consistent with previous wells drilled and completed in those intervals. +One of the key achievements of our drilling and completions program in our Rustler Breaks asset area in 2017 was the success of our wells drilled in the northwestern portion of our acreage position. Early performance from these wells is comparable to or better than Wolfcamp A-XY wells in other portions of our Rustler Breaks asset area. As examples, the Joe Coleman 13-23S-27E RB #206H (Joe Coleman #206H) and the Tom Walters 12-23S-27E RB #203H (Tom Walters #203H) wells tested 1,840 BOE per day (75% oil) and 1,554 BOE per day (74% oil), respectively, during 24-hour initial potential tests. In just nine months of production, the Joe Coleman #206H well has produced approximately 275,000 BOE (71% oil), and in approximately one year of production, the Tom Walters #203H well has produced approximately 255,000 BOE (73% oil). +In addition, two Wolfcamp A-Lower wells completed in 2017 represented our first tests of the Wolfcamp A-Lower interval in the Rustler Breaks asset area. The Guitar 10-24S-28E RB #205H well tested 1,155 BOE per day (75% oil) and the Charlie Sweeney Fed Com #204H well tested 1,188 BOE per day (75% oil), during 24-hour initial potential tests. We believe that these tests confirm the potential of the Wolfcamp A-Lower interval as another completion target in the Rustler Breaks asset area. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY, Wolfcamp A-Lower and Second Bone Spring formations in 2017. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2017, and we completed and turned to sales 13 gross (11.0 net) operated horizontal wells in these asset areas. Most of these wells were completed in the Wolfcamp A-Lower and Second Bone Spring intervals. +In early January 2017, we completed and placed on production the Totum E 18-TTT-C24 NL #211H (Totum #211H) well. This well tested 2,247 BOE per day (72% oil) during a 24-hour initial potential test, which was the highest 24-hour initial potential test for any Wolfcamp A-Lower well completed by us in either our Wolf or Jackson Trust asset areas. We attribute this significant improvement in well performance to both the selection of an improved landing target, identified through the use of 3-D seismic data, and an improved stimulation design. In almost one year of production, the Totum #211H well has produced approximately 300,000 BOE (77% oil). +The Barnett 90-TTT-B01 WF #224H (Barnett #224H) well was our first test of the Wolfcamp B interval in our Wolf asset area. The Barnett #224H well tested 1,803 BOE per day (28% oil) at 4,125 psi during a 24-hour initial potential test. This well exhibited the highest flowing casing pressure on any well yet completed by us in the Wolf asset area. The initial test results and early performance from the Barnett #224H well exceeded our expectations and were similar to those from the Wolfcamp B-Blair interval in the Rustler Breaks asset area. We were pleased with the results of this initial test of the Wolfcamp B interval, which we believe confirms the potential of the Wolfcamp B interval as another completion target in the Wolf asset area. +Arrowhead and Ranger Asset Areas - Eddy and Lea Counties, New Mexico +We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2017. We completed and turned to sales 18 gross (13.4 net) horizontal wells in these asset areas in 2017, including 15 gross (12.7 net) operated and three gross (0.7 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals. +In the second and third quarters of 2017, we completed and turned to sales our first operated horizontal wells in our Arrowhead asset area on our Stebbins leasehold. The Stebbins 20 Federal #123H (Stebbins 20 #123H) well was a Second Bone Spring test, and the Stebbins 20 Federal #133H (Stebbins 20 #133H) well was a Third Bone Spring test. The Stebbins 20 #123H and #133H wells tested 1,010 BOE per day (82% oil) and 1,202 BOE per day (70% oil), respectively, during 24-hour initial potential tests. We completed and turned to sales three additional wells on the Stebbins leasehold in the fourth quarter of 2017, two completed in the Second Bone Spring interval and one completed in the Third Bone Spring interval, with comparable 24-hour initial potential test results to the initial Stebbins wells. +The contiguous nature of the Stebbins acreage has already lent itself to several operational efficiencies, such as batch drilling and completion operations, as well as centralized facilities, each of which contribute to lower overall project costs. Drilling times for the Stebbins wells have improved by as much as 4.1 days since development began on the Stebbins leasehold in 2017. In addition, we expect to be able to drill 1.5 and 2-mile laterals as part of our future development of this acreage. +In the Ranger asset area, we drilled the Airstrip 31-18S-35E RN State Com #132H (Airstrip #132H) well, a Third Bone Spring test north of our Mallon leasehold. The Airstrip #132H well tested 1,263 BOE per day (93% oil) during a 24-hour initial potential test. The Airstrip #132H well has produced approximately 95,000 BOE (92% oil) in its first six months of production. +8 +Table of Contents +During the third quarter of 2017, we installed gas lift on the three Mallon wells—the Mallon 27 Federal Com #1H, #2H and #3H (Mallon #1H, #2H and #3H) wells in the Ranger asset area. Each of these three wells was drilled and completed in the Third Bone Spring and turned to sales in the fourth quarter of 2016. The Mallon wells each tested initially between 2,400 and 2,800 BOE per day (91% oil) and continued to perform well throughout their first ten to eleven months of production prior to the installation of gas lift. Unlike most Third Bone Spring wells completed in the Arrowhead and Ranger asset areas, these wells were tested while flowing up casing (rather than on electrical submersible pump), and the wells continued to flow up casing until the installation of gas lift on each well in the third quarter of 2017. +Each of the Mallon wells exhibited a strong production response to the installation of gas lift. Daily production rates from the Mallon #1H well, which had declined to 600 to 700 Bbl of oil per day, increased to an average of over 1,300 Bbl of oil per day in the first 30 days following gas lift installation. Daily production rates from the Mallon #2H well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of almost 1,500 Bbl of oil per day in the first 30 days following gas lift installation. Daily production rates from the Mallon #3H well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of approximately 900 Bbl of oil per day in the first 30 days following gas lift installation. Natural gas production from these wells responded in a similar fashion. Production declines resumed on these wells at a similar rate to what was observed prior to the installation of gas lift, but from higher daily production rates. The three Mallon wells have produced about 1.3 million BOE (90% oil) in the aggregate, including over 1.1 million Bbl of oil in just over one year of production. +Twin Lakes Asset Area - Lea County, New Mexico +In 2017, we performed our first horizontal test of the Wolfcamp D formation in the eastern portion of our Twin Lakes asset area in northern Lea County, New Mexico. This well, the D. Culbertson 26-15S-36E TL State #234H (D. Culbertson #234H) well, tested approximately 600 BOE per day (82% oil) during a 24-hour initial potential test, including 493 Bbl of oil per day and 640 Mcf of natural gas per day, from a completed lateral length of approximately 4,400 feet. We were pleased and encouraged with the initial results from this discovery well, which we believe confirmed our exploration concept and validated the prospectivity of the Wolfcamp D in the Twin Lakes asset area. To our knowledge, this discovery well is the northernmost horizontal test of the Wolfcamp formation in New Mexico, and this well demonstrates the potential for horizontal exploitation and development of the Wolfcamp formation far to the north of the most active areas of current drilling in the Wolfcamp play in the Delaware Basin. Overall, the D. Culbertson #234H well provided us with a solid first step in our understanding of the Wolfcamp D formation in this area. We plan to drill a second Wolfcamp D test on the western portion of our Twin Lakes acreage position in 2018. +Antelope Ridge Asset Area - Lea County, New Mexico +We drilled our first operated well in the Antelope Ridge asset area, the Florence State 23-23S-34E #202H (Florence #202H) well, in mid-November 2017. This well was completed and turned to sales in January 2018. The Florence #202H well tested 1,947 BOE per day (81% oil) at 1,700 psi during a 24-hour initial potential test. We were pleased with the initial performance of this well and believe it confirms the prospectivity of the Antelope Ridge asset area. We intend to continue the delineation of our acreage position in Antelope Ridge, where other operators in the area have successfully tested the Brushy Canyon, First, Second and Third Bone Spring and Upper Wolfcamp intervals. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2017 , our properties included approximately 31,800 gross ( 29,000 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 86% of our Eagle Ford acreage was held by production at December 31, 2017 , and approximately 98% of our Eagle Ford acreage was either held by production at December 31, 2017 or not burdened by lease expirations before 2019 . +In 2017, we drilled and completed five operated wells in the Eagle Ford shale in South Texas. Two of these wells, the Falls City #1H and #2H wells, both located in Karnes County, were turned to sales in mid-June 2017. The other three wells, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells, all located in La Salle County, were turned to sales in early July 2017. We have a 100% working interest in each of these five wells. These five Eagle Ford shale wells tested +9 +Table of Contents +between approximately 1,100 and 1,700 BOE per day at oil cuts between 90% and 94% during 24-hour initial potential tests. The initial results from this five-well drilling program almost doubled our average daily oil equivalent production from the Eagle Ford shale in the third quarter of 2017, as compared to production levels in the second quarter of 2017. +At December 31, 2017 , the Falls City #1H and #2H wells had the highest estimated ultimate oil recoveries of any of our wells in the Eagle Ford shale. Further, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells were drilled and completed for an average of approximately $4.5 million per well, among the lowest well costs we have achieved in the Eagle Ford shale. Despite not being active in the Eagle Ford shale since the second quarter of 2015, we were able to achieve our fastest drilling time for an Eagle Ford shale well from spud to total depth in one of these Martin Ranch wells. +Our average daily oil equivalent production from the Eagle Ford shale decreased 11% to 4,413 BOE per day, including 3,475 Bbl of oil per day and 5.6 MMcf of natural gas per day, during 2017 , as compared to 4,952 BOE per day, including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016 . For the year ended December 31, 2017 , 11% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2016 , approximately 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2017 , approximately 8% of our estimated total proved oil and natural gas reserves, or 12.3 million BOE, was attributable to the Eagle Ford shale, including approximately 9.2 million Bbl of oil and 19.0 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 11% of our proved oil reserves and 5% of our proved natural gas reserves at December 31, 2017 , as compared to approximately 18% of our proved oil reserves and 7% of our proved natural gas reserves at December 31, 2016 . +At December 31, 2017 , we had identified 241 gross ( 208.5 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2017 , these 241 gross ( 208.5 net) identified drilling locations included only 12 gross (12.0 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2017 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though recent activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals. +Northwest Louisiana and East Texas — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017 , although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that were turned to sales in 2017 . We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2018 . +At December 31, 2017 , we held approximately 25,500 gross ( 22,800 net) acres in Northwest Louisiana and East Texas, including 19,600 gross ( 12,000 net) acres in the Haynesville shale play and 21,100 gross (18,600 net) acres in the Cotton Valley +10 +Table of Contents +play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the 13,200 gross ( 6,400 net) acres that we consider to be in the core area of the Haynesville play. We believe the core area of the play includes that area in which the most Haynesville shale wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well from an approximate 5,000-foot horizontal lateral. +For the year ended December 31, 2017 , approximately 13% of our average daily oil equivalent production, or 5,060 BOE per day, including 12 Bbl of oil per day and 30.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 29% of our daily natural gas production for 2017, but oil production from these properties comprised only about 0.1% of our daily oil production during 2017 , as compared to approximately 50% of our daily natural gas production and approximately 0.1% of our daily oil production during 2016 . During the year ended December 31, 2016 , approximately 25% of our average daily oil equivalent production, or 6,920 BOE per day, including 12 Bbl of oil per day and 41.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2017 , approximately 27% of our daily natural gas production, or 28.3 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 2% , or 2.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2016 , approximately 47% of our daily natural gas production, or 39.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.3 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2017 , approximately 7% of our estimated total proved reserves, or 10.1 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 1.3 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2017 , we had identified 413 gross ( 102.0 net) engineered locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.0 net) engineered locations for potential future drilling in the Cotton Valley formation. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 413 gross ( 102.0 net) locations identified for future drilling on our Haynesville acreage, 339 gross (49.0 net) locations have been identified within the 13,200 gross ( 6,400 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2017 , these potential future drilling locations included only nine gross (3.3 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Midstream Segment +The midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. Through the ownership and operation of these facilities, we improve our ability to manage costs and control the timing of bringing on new production, and we enhance the value received for our production. As noted above, we contributed the Delaware Midstream Assets to San Mateo in February 2017 and continued to operate them, as well as San Mateo’s other assets, at December 31, 2017 . +Southeast New Mexico and West Texas — Delaware Basin +During 2017, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental 200 MMcf per day to the existing 60 MMcf per day of inlet cryogenic natural gas processing capacity. At February 21, 2018 , the expansion project was proceeding on schedule with the plant expansion expected to become operational by the end of the first quarter of 2018. At December 31, 2017 and February 21, 2018 , the Black River Processing Plant was effectively full with Matador-operated natural gas. The Black River Processing Plant and associated gathering system were built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. It may also provide additional income through the gathering and processing of third-party natural gas after the plant expansion becomes operational. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks. In addition, in October 2017 and January 2018, San Mateo placed into service its second and third, respectively, commercial salt water disposal wells in the Rustler Breaks +11 +Table of Contents +asset area. San Mateo disposed of approximately 7.9 million Bbl of Matador-operated and third-party salt water in the Rustler Breaks asset area during 2017 and, at February 21, 2018 , its salt water disposal wells there had a disposal capacity of approximately 90,000 Bbl of salt water per day. San Mateo plans to add to that disposal capacity in 2018 by upgrading two of the existing salt water disposal wells by installing larger tubing and drilling and completing at least two additional commercial salt water disposal wells and constructing the associated commercial salt water disposal facilities in the Rustler Breaks asset area. We expect these additional wells to be completed in 2018, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to a total of five. At February 21, 2018 , San Mateo was also building out an oil gathering and transportation system in the Rustler Breaks asset area. +In our Wolf asset area in Loving County, Texas, San Mateo has oil, natural gas and salt water gathering systems that gather our oil, natural gas and water production. We retained this three-pipeline system following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo in February 2017. During 2017 , San Mateo disposed of approximately 15.5 million Bbl of salt water in the Wolf asset area, including disposal of third-party salt water on a commercial basis. San Mateo completed its third salt water disposal well in the Wolf asset area during 2017, increasing San Mateo’s disposal capacity in the Wolf asset area to approximately 70,000 Bbl of salt water per day. At February 21, 2018 , San Mateo was also expanding its oil gathering system in the Wolf asset area. +South Texas / Northwest Louisiana and East Texas +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases and from third parties. We also have five non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2017, 2016 and 2015 . +Year Ended December 31, +2017 +2016 +2015 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +7,851 +5,096 +4,492 +Natural gas (Bcf) +38.2 +30.5 +27.7 +Total oil equivalent (MBOE) (1) +14,212 +10,180 +9,109 +Average daily production (BOE/d) (1) +38,936 +27,813 +24,955 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +49.28 +$ +41.19 +$ +45.27 +Oil, with realized derivatives (per Bbl) +$ +48.81 +$ +42.34 +$ +59.13 +Natural gas, without realized derivatives (per Mcf) +$ +3.72 +$ +2.66 +$ +2.71 +Natural gas, with realized derivatives (per Mcf) +$ +3.70 +$ +2.78 +$ +3.24 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +4.10 +$ +4.23 +$ +3.91 +Lease operating +$ +4.74 +$ +5.52 +$ +6.01 +Plant and other midstream services operating +$ +0.92 +$ +0.53 +$ +0.38 +Depletion, depreciation and amortization +$ +12.49 +$ +11.99 +$ +19.63 +General and administrative +$ +4.65 +$ +5.41 +$ +5.50 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +12 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +6,579 +1,268 +— +4 +7,851 +Natural gas (Bcf) +25.1 +2.0 +10.3 +0.8 +38.2 +Total oil equivalent (MBOE) (3) +10,754 +1,611 +1,714 +133 +14,212 +Percentage of total annual net production +75.7 +% +11.3 +% +12.1 +% +0.9 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +18,023 +3,475 +— +12 +21,510 +Natural gas (MMcf/d) +68.6 +5.6 +28.3 +2.1 +104.6 +Total oil equivalent (BOE/d) +29,463 +4,413 +4,697 +363 +38,936 +Average Sales Prices (4) +Oil (per Bbl) +$ +49.08 +$ +50.29 +$ +— +$ +45.52 +$ +49.28 +Natural gas (per Mcf) +$ +4.03 +$ +4.69 +$ +2.83 +$ +2.79 +$ +3.72 +Total oil equivalent (per BOE) +$ +39.41 +$ +45.58 +$ +16.96 +$ +17.69 +$ +37.20 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.80 +$ +10.92 +$ +4.21 +$ +16.77 +$ +6.29 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +3,805 +1,286 +— +5 +5,096 +Natural gas (Bcf) +12.2 +3.1 +14.3 +0.9 +30.5 +Total oil equivalent (MBOE) (3) +5,834 +1,813 +2,385 +148 +10,180 +Percentage of total annual net production +57.3 +% +17.8 +% +23.4 +% +1.5 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +10,395 +3,517 +— +12 +13,924 +Natural gas (MMcf/d) +33.3 +8.6 +39.1 +2.3 +83.3 +Total oil equivalent (BOE/d) +15,941 +4,952 +6,517 +403 +27,813 +Average Sales Prices (4) +Oil (per Bbl) +$ +41.76 +$ +39.49 +$ +— +$ +38.78 +$ +41.19 +Natural gas (per Mcf) +$ +3.15 +$ +3.11 +$ +2.17 +$ +2.27 +$ +2.66 +Total oil equivalent (per BOE) +$ +33.81 +$ +33.46 +$ +13.04 +$ +14.39 +$ +28.60 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +7.32 +$ +12.74 +$ +4.73 +$ +17.07 +$ +7.82 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +1,697 +2,789 +— +6 +4,492 +Natural gas (Bcf) +4.1 +5.7 +16.9 +1.0 +27.7 +Total oil equivalent (MBOE) (3) +2,379 +3,746 +2,822 +162 +9,109 +Percentage of total annual net production +26.1 +% +41.1 +% +31.0 +% +1.8 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +4,648 +7,642 +— +16 +12,306 +Natural gas (MMcf/d) +11.2 +15.7 +46.4 +2.6 +75.9 +Total oil equivalent (BOE/d) +6,518 +10,263 +7,731 +443 +24,955 +Average Sales Prices (4) +Oil (per Bbl) +$ +43.54 +$ +46.33 +$ +— +$ +43.68 +$ +45.27 +Natural gas (per Mcf) +$ +3.00 +$ +3.17 +$ +2.49 +$ +2.45 +$ +2.71 +Total oil equivalent (per BOE) +$ +36.21 +$ +39.35 +$ +14.97 +$ +15.69 +$ +30.56 +Production Costs (5) +Lease operating, transportation and processing (per BOE) (6) +$ +8.84 +$ +9.25 +$ +4.91 +$ +19.23 +$ +7.90 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +(6) +Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016. +Our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 increased 40% from our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, as compared to 27,813 BOE per day for the year ended December 31, 2016 . Our average daily oil production for the year ended December 31, 2017 was 21,510 Bbl of oil per day, an increase of 54% from 13,924 Bbl of oil per day for the year ended December 31, 2016 . Our average daily natural gas production for the year ended December 31, 2017 was 104.6 MMcf of natural gas per day, an increase of 25% from 83.3 MMcf of natural gas per day for the year ended December 31, 2016 . +Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where, as of December 31, 2016, we had not drilled any new operated wells since the second quarter of 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, as compared to 24,955 BOE per day for the year ended December 31, 2015 . Our average daily oil production for the year ended December 31, 2016 was 13,924 Bbl of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year ended December 31, 2015 . Our average daily natural gas production for the year ended December 31, 2016 was 83.3 MMcf of natural gas per day, an increase of 10% from 75.9 MMcf of natural gas per day for the year ended December 31, 2015 . +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2017 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 75% in all wells that we operated at December 31, 2017 . For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 11%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +372 +174.8 +78 +36.7 +450 +211.5 +South Texas: +Eagle Ford (2) +138 +115.8 +4 +4.0 +142 +119.8 +Northwest Louisiana/East Texas: +Haynesville +— +— +217 +20.5 +217 +20.5 +Cotton Valley (3) +2 +2.0 +79 +52.3 +81 +54.3 +Area Total +2 +2.0 +296 +72.8 +298 +74.8 +Total +512 +292.6 +378 +113.5 +890 +406.1 +__________________ +(1) +Includes 217 gross (55.4 net) vertical wells that were acquired in multiple transactions. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2017, 2016 and 2015 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids (“NGLs”) associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +16 +Table of Contents +At December 31, (1) +2017 +2016 +2015 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +86,743 +56,977 +45,644 +Natural Gas (Bcf) (3) +396.2 +292.6 +236.9 +Total (MBOE) (4) +152,771 +105,752 +85,127 +Estimated proved developed reserves: +Oil (MBbl) +36,966 +22,604 +17,129 +Natural Gas (Bcf) (3) +190.1 +126.8 +101.4 +Total (MBOE) (4) +68,651 +43,731 +34,037 +Percent developed +44.9 +% +41.4 +% +40.0 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +49,777 +34,373 +28,515 +Natural Gas (Bcf) (3) +206.1 +165.9 +135.5 +Total (MBOE) (4) +84,120 +62,021 +51,090 +Standardized Measure (5) (in millions) +$ +1,258.6 +$ +575.0 +$ +529.2 +PV-10 (6) (in millions) +$ +1,333.4 +$ +581.5 +$ +541.6 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas, for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, and for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) +Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated properties in the Haynesville shale. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classified proved undeveloped reserves from our total proved reserves in 2016. +(5) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(6) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2017, 2016 and 2015 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2017, 2016 and 2015 were, in millions, $74.8 , $6.5 and $12.4 , respectively. +Our estimated total proved oil and natural gas reserves increase d 44% from 105.8 million BOE at December 31, 2016 to 152.8 million BOE at December 31, 2017 . We added 45.2 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2017, approximately 3.2 times our 2017 annual production of 14.2 million BOE. Our proved oil reserves grew 52% from approximately 57.0 million Bbl at December 31, 2016 to approximately 86.7 million Bbl at December 31, 2017 . Our proved natural gas reserves increase d 35% from 292.6 Bcf at December 31, 2016 to 396.2 Bcf at December 31, 2017 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2017. We incurred approximately 9.6 million BOE in net upward revisions to our proved reserves during 2017 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017, as compared to December 31, 2016. Our proved reserves to production ratio at December 31, 2017 was 10.8 x, an increase of 4% from 10.4 x at December 31, 2016. +17 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increase d 119% from $575.0 million at December 31, 2016 to $1.26 billion at December 31, 2017 . The PV-10 of our total proved oil and natural gas reserves increase d 129% from $581.5 million at December 31, 2016 to $1.33 billion at December 31, 2017 . The increases in our Standardized Measure and PV-10 are primarily a result of our delineation and development operations in the Delaware Basin during 2017 and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017 , as compared to December 31, 2016 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2017 were $47.79 per Bbl and $2.98 per MMBtu, an increase of 22% and 20% , respectively, as compared to average oil and natural gas prices of $39.25 per Bbl and $2.48 per MMBtu used to estimate proved reserves at December 31, 2016 . Our total proved reserves were made up of 57% oil and 43% natural gas at December 31, 2017 , as compared to 54% oil and 46% natural gas at December 31, 2016 . +Our proved developed oil and natural gas reserves increase d 57% from 43.7 million BOE at December 31, 2016 to 68.7 million BOE at December 31, 2017 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 64% from 22.6 million Bbl at December 31, 2016 to 37.0 million Bbl at December 31, 2017 . Our proved developed natural gas reserves increase d 50% from 126.8 Bcf at December 31, 2016 to 190.1 Bcf at December 31, 2017 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2017 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2016 +43,731 +Extensions and discoveries +14,335 +Purchases of minerals-in-place +1,614 +Revisions of prior estimates +6,375 +Production +(14,212 +) +Conversion of proved undeveloped to proved developed +16,808 +As of December 31, 2017 +68,651 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d 36% from 62.0 million BOE at December 31, 2016 to 84.1 million BOE at December 31, 2017 . Our proved undeveloped oil and natural gas reserves increased from 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016 to 49.8 million Bbl and 206.1 Bcf, respectively, at December 31, 2017 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2017 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2017 within five years of booking these reserves. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2017 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2016 +62,021 +Extensions and discoveries +30,834 +Purchases of minerals-in-place +4,868 +Revisions of prior estimates +3,205 +Conversion of proved undeveloped to proved developed +(16,808 +) +As of December 31, 2017 +84,120 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +The following table sets forth, since 2014, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2014 +3,780 +44.7 +11,223 +$ +201,950 +2015 +2,854 +23.4 +6,747 +104,989 +2016 +4,705 +13.1 +6,883 +94,579 +2017 +9,300 +45.0 +16,808 +211,860 +Total +20,639 +126.2 +41,661 +$ +613,378 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2017 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +77,508 +308.9 +128,999 +$ +1,088.4 +$ +1,153.1 +South Texas: +Eagle Ford (5) +9,189 +19.0 +12,346 +130.6 +138.4 +Northwest Louisiana/East Texas: +Haynesville +— +60.7 +10,106 +35.7 +37.8 +Cotton Valley (6) +46 +7.6 +1,320 +3.9 +4.1 +Area Total +46 +68.3 +11,426 +39.6 +41.9 +Total +86,743 +396.2 +152,771 +$ +1,258.6 +$ +1,333.4 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2017 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2017 were approximately $ 74.8 million . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational +19 +Table of Contents +methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 40 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2017 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +100,500 +50,600 +99,100 +63,400 +199,600 +114,000 +South Texas: +Eagle Ford +27,600 +24,900 +4,200 +4,100 +31,800 +29,000 +Northwest Louisiana/East Texas: +Haynesville +16,200 +8,600 +3,400 +3,400 +19,600 +12,000 +Cotton Valley +17,600 +15,600 +3,500 +3,000 +21,100 +18,600 +Area Total (1) +21,500 +19,300 +4,000 +3,500 +25,500 +22,800 +Total +149,600 +94,800 +107,300 +71,000 +256,900 +165,800 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2017 that will expire over the next four years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2022 and beyond represents an immaterial amount of our overall undeveloped acreage. +20 +Table of Contents +Acres +Acres +Acres +Acres +Expiring 2018 +Expiring 2019 +Expiring 2020 +Expiring 2021 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +25,600 +18,900 +14,400 +11,300 +8,900 +7,800 +19,000 +11,700 +South Texas: +Eagle Ford +900 +700 +1,500 +1,400 +1,600 +1,600 +— +— +Northwest Louisiana/East Texas: +Haynesville +— +— +300 +300 +200 +200 +— +— +Cotton Valley +— +— +— +— +— +— +— +— +Area Total (2) +— +— +300 +300 +200 +200 +— +— +Total +26,500 +19,600 +16,200 +13,000 +10,700 +9,600 +19,000 +11,700 +__________________ +(1) +Approximately 59% of the acreage expiring in the Delaware Basin in the next four years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of the expiring acreage through our 2018 drilling activities or by paying an additional lease bonus, where applicable. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2017 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2017, 2016 and 2015 . +Year Ended December 31, +2017 +2016 +2015 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +72 +43.7 +44 +23.5 +53 +26.7 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +33 +22.3 +28 +15.6 +28 +17.5 +Dry +— +— +— +— +— +— +Total Wells +Productive +105 +66.0 +72 +39.1 +81 +44.2 +Dry +— +— +— +— +— +— +Marketing and Customers +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. +21 +Table of Contents +The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the years ended December 31, 2017, 2016 and 2015 , we had four, three and three significant purchasers, respectively, that accounted for approximately 60% , 48% and 59% , respectively, of our total oil, natural gas and NGL revenues. Due to the nature of the markets for oil, natural gas and NGLs, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. We expect that some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +22 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s +23 +Table of Contents +jurisdiction under the Interstate Commerce Act, or the ICA. We believed, as of February 21, 2018 , that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and the crude oil pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. +In 2005, Congress enacted the Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +At February 21, 2018 , San Mateo was developing a common carrier pipeline that we expect to be subject to regulation by FERC under the ICA and the Energy Policy Act of 1992, or EP Act. The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +24 +Table of Contents +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors — Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management, or the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have also been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal +25 +Table of Contents +fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the Environmental Protection Agency, or the EPA, has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to +26 +Table of Contents +Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2017 , we owned and operated over fifteen underground injection wells and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission, or TRC, adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and +27 +Table of Contents +sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2017 , we had 217 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +28 +Table of Contents +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Strategic Planning and Compensation Committee, Corporate Governance Committee, Executive Committee and Nominating Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +Item 1A. Risk Factors. +Risks Related to the Oil and Natural Gas Industry and Our Business +Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. +The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our third amended and restated revolving credit agreement, as amended (the “Credit Agreement”), and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2017 , the average price of oil was $50.80 per Bbl, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $3.02 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Starting in the first quarter of 2017 , oil and natural gas prices began to increase from their previous lows. Oil prices increased 42% from $42.53 per Bbl in late June 2017 to $60.42 per Bbl in late December 2017 , and natural gas prices increased 34% from $2.56 per MMBtu in late February 2017 to $3.42 per MMBtu in mid-May 2017 , but had declined to $2.60 per MMBtu in late December 2017 . +Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines caused us to recognize full-cost ceiling impairments in each of the quarters of 2015 and in the first two quarters of 2016, and should prices decline again, we may recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.” +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• +the domestic and foreign supply of, and demand for, oil and natural gas; +• +the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; +• +the prices and availability of competitors’ supplies of oil and natural gas; +• +the price and quantity of foreign imports; +• +the impact of U.S. dollar exchange rates; +• +domestic and foreign governmental regulations and taxes; +• +speculative trading of oil and natural gas futures contracts; +• +the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs; +• +the availability of refining capacity; +• +the prices and availability of alternative fuel sources; +29 +Table of Contents +• +weather conditions and natural disasters; +• +political conditions in or affecting oil and natural gas producing regions or countries, including the United States, Middle East, South America and Russia; +• +the continued threat of terrorism and the impact of military action and civil unrest; +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; +• +the level of global oil and natural gas inventories and exploration and production activity; +• +the impact of energy conservation efforts; +• +technological advances affecting energy consumption; and +• +overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil and natural gas prices do not necessarily fluctuate in direct relation to each other. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or to cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our estimated proved oil and natural gas reserves; +• +the amount of oil and natural gas we produce from existing wells; +• +the prices at which we sell our production; +• +the costs of developing and producing our oil and natural gas reserves; +• +the costs of constructing, operating and maintaining our midstream facilities; +• +our ability to attract third-party customers for our midstream services; +• +our ability to acquire, locate and produce new reserves; +• +the ability and willingness of banks to lend to us; and +• +our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy +30 +Table of Contents +industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. +Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• +general economic and industry conditions, including the prices received for oil and natural gas; +• +shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• +potential drainage of oil and natural gas from our properties by adjacent operators; +• +the existence or magnitude of faults or unanticipated geological features; +• +loss of or damage to oilfield development and service tools; +• +accidents, equipment failures or mechanical problems; +• +title defects of the underlying properties; +• +increases in severance taxes; +• +adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• +domestic and foreign governmental regulations; and +• +proximity to and capacity of gathering, processing and transportation facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. For example, risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +31 +Table of Contents +• +landing our wellbore in the desired drilling zone; +• +staying in the desired drilling zone while drilling horizontally through the formation; +• +running our casing the entire length of the wellbore; +• +fracture stimulating the planned number of stages; and +• +being able to run tools and other equipment consistently through the horizontal wellbore. +If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• +natural disasters; +• +adverse weather conditions; +• +loss of drilling fluid circulation; +• +blowouts where oil or natural gas flows uncontrolled at a wellhead; +• +cratering or collapse of the formation; +• +pipe or cement leaks, failures or casing collapses; +• +damage to pipelines, processing plants and disposal wells and associated facilities; +• +fires or explosions; +• +releases of hazardous substances or other waste materials that cause environmental damage; +• +pressures or irregularities in formations; and +• +equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana and East Texas. In 2015, 2016 and 2017, the vast majority of our capital expenditures were allocated to +32 +Table of Contents +the Delaware Basin. We expect that substantially all of our capital expenditures in 2018 will continue to be in the Delaware Basin. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil, condensate and salt water trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In recent years, certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +We May Not Be Able to Generate Sufficient Cash to Service All of Our Indebtedness and May Be Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May Not Be Successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We May Incur Additional Indebtedness, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. +As of February 21, 2018 , the maximum facility amount under the Credit Agreement was $500.0 million and our elected borrowing commitment was $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing +33 +Table of Contents +base, maximum facility amount and elected borrowing commitment. At February 21, 2018 , we had available borrowings of approximately $397.9 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties, and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement), we may incur significant amounts of additional indebtedness, including under our Credit Agreement, through the issuance of additional notes or otherwise, in order to fund acquisitions, develop our properties or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• +requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• +increasing our vulnerability to general adverse economic and industry conditions; +• +placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• +restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• +increasing the risk that we may default on our debt obligations. +The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination, and We Are Subject to Interest Rate Risk under Our Credit Agreement. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 21, 2018 , our borrowing base was $525.0 million , and we had no outstanding borrowings under, and approximately $2.1 million in outstanding letters of credit issued pursuant to, the Credit Agreement. As of February 21, 2018 , the maximum facility amount under the Credit Agreement was $500.0 million and our elected borrowing commitment was $400.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment. We could be required to repay a portion of any outstanding bank debt to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +34 +Table of Contents +The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions. +Our Credit Agreement and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• +consolidate, merge or transfer all or substantially all of our assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. Low oil and natural gas prices or any decline in the prices of oil or natural gas may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement or indenture is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our Credit Rating May Be Downgraded, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations. +As of February 21, 2018 , our corporate credit rating from Standard & Poor’s Rating Services was “B” and our corporate credit rating from Moody’s Investors Service was “B2.” We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +We Depend upon Several Significant Purchasers for the Sale of Most of Our Oil and Natural Gas Production. The Loss of One or More of These Purchasers Could, Among Other Factors, Limit Our Access to Suitable Markets for the Oil and Natural Gas We Produce. +We depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the years ended December 31, 2017, 2016 and 2015, we had four, three and three significant purchasers, respectively, that collectively accounted for approximately 60% , 48% and 59% , respectively, of our total oil, natural gas and NGL revenues. We cannot assure you that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. +35 +Table of Contents +The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +If Regulatory Changes Prevent Our Ability to Continue to Drill Wells in the Manner We Have Been, It Could Have a Material Adverse Impact on Our Future Production Results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +36 +Table of Contents +We Conduct a Portion of Our Operations through Joint Ventures, Which Subjects Us to Additional Risks That Could Have a Material Adverse Effect on the Success of These Operations, Our Financial Position, Results of Operations or Cash Flows. +We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for San Mateo and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows. +Our Midstream Operations Are Subject to Operational Risks, Which Could Result in Significant Damages and the Loss of Revenue. +San Mateo owns, and we operate, the Black River Processing Plant. There are significant risks associated with the operation of cryogenic natural gas processing plants. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a cryogenic natural gas processing plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells located in the Rustler Breaks asset area. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flow could be adversely affected. +Because of the Natural Decline in Production in the Regions of San Mateo’s Midstream Operations, San Mateo’s Long-Term Success Depends on its Ability to Obtain New Sources of Supplies, Which Depends on Certain Factors Beyond San Mateo’s Control. Any Decrease in Supplies to its Midstream Facilities Could Adversely Affect San Mateo’s Business and Operating Results. +San Mateo’s midstream facilities are or will be connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new supplies. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of third-party activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over third-party producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We Do Not Own All of the Land on Which Our Midstream Assets Are Located, Which Could Disrupt Our Operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land use if we do not have valid rights-of-way or +37 +Table of Contents +leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Construction of Midstream Projects Subjects Us to Risks of Construction Delays, Cost Over-Runs, Limitations on Our Growth and Negative Effects on Our Financial Condition, Results of Operations, Cash Flows and Liquidity. +From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as San Mateo’s expansion of the Black River Processing Plant or the drilling of additional commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of salt water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws That Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. +The operations of our midstream business, including San Mateo, and the operations of the third parties on whom we rely for gathering, processing and transportation services, are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. Substantial costs may be incurred in order to comply with existing laws and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new laws and regulations become applicable to operations, these changes may affect the costs that we pay for such services or the results of our midstream business, including San Mateo. Similarly, a failure to comply with such laws and regulations by us or the parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” +Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the judgment of the persons preparing the estimate; and +• +the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production +38 +Table of Contents +declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +actual costs and timing of development and production expenditures; +• +the amount and timing of actual production; and +• +changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 55% of Our Total Proved Reserves at December 31, 2017 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. +At December 31, 2017 , approximately 55% of our total proved reserves were undeveloped and less than 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms and seasonal conditions. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. +At December 31, 2017 , we had leasehold interests in approximately 53,900 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2022 . Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling +39 +Table of Contents +activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic and geological data can be expensive to license or obtain and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. +Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +40 +Table of Contents +The Marketability of Our Production Is Dependent upon Oil, Natural Gas and NGL Gathering, Processing and Transportation Facilities, and the Unavailability of Satisfactory Oil, Natural Gas and NGL Gathering, Processing and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas, which would decrease the volumes sold from our wells, and, in certain circumstances, would require us to pay royalties on such flared natural gas. +The disruption of our or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering, disposal or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2018 . If we were required to shut in our production or flare our natural gas for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third-Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows. +Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +41 +Table of Contents +We Have Entered into Certain Long-Term Contracts That Require Us to Pay Fees to Our Service Providers Based on Minimum Volumes Regardless of Actual Volume Throughput and That May Limit Our Ability to Use Other Service Providers. +In connection with the sale of the Loving County Processing System in October 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement covering the anticipated natural gas production from a significant portion of our acreage in the Wolf asset area in the Delaware Basin (the “Wolf Gathering Agreement”). In addition, in connection with the formation of San Mateo, we entered into certain 15-year fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements covering the Rustler Breaks and Wolf asset areas and a natural gas processing agreement covering the Rustler Breaks asset area (collectively, the “Joint Venture Agreements”). We have also entered into an 18-year fixed-fee natural gas transportation agreement relating to transportation of a portion of the residue natural gas from the tailgate of the Black River Processing Plant. In each of these agreements we have provided certain minimum volume commitments. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to fulfill our obligations under these agreements. In addition, in late 2017, we also entered into a fixed-fee NGL transportation and fractionation agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing Plant. These agreements obligate us to pay fees on minimum volumes to our service providers (including San Mateo) regardless of actual throughput. As of December 31, 2017, our long-term contractual obligations under agreements with minimum volume commitments, including the Joint Venture Agreements, totaled approximately $432.8 million over the terms of the agreements. If we have insufficient production to meet the minimum volumes, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to the Wolf Gathering Agreement, the Joint Venture Agreements and other agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to EnLink, San Mateo and other midstream companies, as applicable. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +We Have Limited Control over Activities on Properties We Do Not Operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• +the timing and amount of capital expenditures; +• +the operator’s expertise and financial resources; +• +the rate of production of reserves, if any; +• +approval of other participants in drilling wells; and +• +selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +42 +Table of Contents +A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know about or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. +Before acquiring oil and natural gas properties, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +Our Ability to Complete Dispositions of Assets, or Interests in Assets, May Be Subject to Factors Beyond Our Control, and in Certain Cases We May Be Required to Retain Liabilities for Certain Matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. +If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the mineral interest owner or if the property has other title deficiencies, our interest +43 +Table of Contents +would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. +It is not our practice in all acquisitions of oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have: +• +downward adjustments to our estimated proved reserves; +• +increases in our estimates of development costs; or +• +deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ +44 +Table of Contents +the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. As of February 21, 2018 , we had approximately 55% and 40% of our estimated remaining 2018 oil and natural gas production, respectively, hedged. We currently have no hedges in place for NGLs and no hedges in place beyond 2018 for oil and natural gas. +An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. For example, we sell much of our natural gas produced from the Delaware Basin at the Waha Hub. The differential between the Waha Hub index and the Henry Hub index has recently increased as compared to prior years. We have derivative contracts covering the amount of the basis differentials we experience with respect to only a portion of our production. As such, we will be exposed to any increase in such differentials not covered by such contracts. +We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. In addition to expenditures required in order for us to comply with such laws and regulations, these expenditures could also include payments for: +• +personal injuries; +• +property damage; +• +containment and clean-up of oil and other spills; +• +management and disposal of hazardous materials; +• +remediation, clean-up costs and natural resource damages; and +• +other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or facilities are located, or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have an adverse impact on our ability to develop and produce our reserves. +45 +Table of Contents +We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The recently enacted Tax Cuts and Jobs Act did not include any of these proposals, except for the repeal of the domestic manufacturing tax deduction for oil and gas companies. However, it is possible that such provisions could be proposed in the future. The passage of any legislation or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods. +The recently enacted Tax Cuts and Jobs Act includes provisions which, beginning in 2018, generally will (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our business interest income) for the year, (ii) permit us to offset only 80% (rather than 100%) of our taxable income with net operating losses we generate after 2017 and (iii) limit our ability to deduct certain elements of executive compensation. Interest expense and net operating losses subject to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the Tax Cuts and Jobs Act repealed the domestic manufacturing tax deduction for oil and natural gas companies. These tax law changes could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might otherwise not have incurred, in the absence of these tax law changes. +Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local-level laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, the BLM issued final rules to regulate hydraulic fracturing on federal lands in March 2015, although these rules were rescinded by rule in December 2017. +In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Moreover, while the scientific community and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity, some state regulatory agencies have modified their regulations or guidance to regulate potential causes of induced seismicity, including fluid injection or oil and natural gas extraction. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in +46 +Table of Contents +unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The Potential Adoption of Federal, State and Local Legislation and Regulations Intended to Address Potential Induced Seismic Activity in the Areas in Which We Operate Could Restrict Our Drilling and Production Activities, as well as Our Ability to Dispose of Produced Water Gathered from Such Activities, Which Could Decrease San Mateo’s Revenues and Result in Increased Costs and Additional Operating Restrictions or Delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and natural gas waste disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas, have modified their regulations or guidance to mitigate potential causes of induced seismicity. +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. We and San Mateo dispose of large volumes of produced water gathered from our or third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could decrease San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. In June 2017, the Trump administration announced its intention for the United States to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest date the United States can withdraw is November 2020. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and natural gas industry. Any future international agreements, federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs, adversely affecting our profits, and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and +47 +Table of Contents +increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. This more stringent ozone NAAQS could result in additional areas being designated as non-attainment, including areas in which we operate, which may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. The EPA anticipates promulgating final area designations under the new standard in the first half of 2018. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with this revised regulation, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented. The EPA’s final rule has been judicially challenged by both industry and other interested parties, and the outcome of this litigation may also impact implementation and revisions to the rule. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. The BLM issued a two-year stay of these requirements in December 2017 and has indicated that the requirements could be rescinded or significantly revised in the future. Litigation challenging the delay has been filed by certain environmental groups and states. In February 2018, a federal district judge in California issued a preliminary injunction requiring the BLM to enforce these regulations. If not withdrawn or significantly revised, these rules are expected to result in an increase to our operating costs and changes in our operations. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs on our operations. +We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as TRC could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and +48 +Table of Contents +federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. We believe that certain of our crude oil pipelines meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. However, whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The Rates of Our Regulated Assets are Subject to Review and Reporting by Federal Regulators, Which Could Adversely Affect Our Revenues. +Our proposed crude oil pipelines in New Mexico to be developed and owned by San Mateo are expected to transport crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found to be in excess of levels justified by our cost of service, FERC could order us to reduce our rates, and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found to be in excess of our cost of services, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. We anticipate that the shippers on our FERC-regulated pipeline will agree not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective agreements; however, other current or future shippers may still challenge our tariff rates. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on our proposed interstate oil pipeline and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.2 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. The nature of our gathering facilities is such that we have not yet been regulated by FERC. San Mateo’s proposed crude oil pipelines in New Mexico are expected to transport crude oil in interstate commerce and be subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. During the last quarter of 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +49 +Table of Contents +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or Financial Loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. +While we have not experienced any material losses due to cyber incidents, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access +50 +Table of Contents +to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Risks Relating to Our Common Stock +The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2017 , our stock price fluctuated between a high of $31.59 and a low of $20.13 . In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• +our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• +quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• +changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• +speculation in the press or investment community; +• +announcement or consummation of acquisitions or dispositions by us; +• +public reaction to our press releases, announcements and filings with the SEC; +• +sales of our common stock by us or shareholders, or the perception that such sales may occur; +• +general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• +the realization of any of the risk factors presented in this Annual Report; +• +the recruitment or departure of key personnel; +• +commencement of or involvement in litigation; +• +the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• +changes in market valuations of companies similar to ours; and +• +domestic and international economic, legal and regulatory factors unrelated to our performance. +If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Further, our remediation efforts may not enable us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +51 +Table of Contents +We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. +We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. +Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• +authorization for our Board of Directors to issue preferred stock without shareholder approval; +• +a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• +the prohibition of cumulative voting in the election of directors; and +• +a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +Our Directors and Executive Officers Own a Significant Percentage of Our Equity, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. +As of February 21, 2018 , our directors and executive officers beneficially owned approximately 11% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +52 +Table of Contents +Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 13 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are a party to several lawsuits encountered in the ordinary course of our business. While the ultimate outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on our financial condition, results of operations or cash flows. +Item 4. Mine Safety Disclosures. +Not applicable. +53 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 21, 2018 , we had 109,248,747 shares of common stock outstanding held by approximately 300 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated. +2017 +2016 +High +Low +High +Low +First Quarter +$ +28.51 +$ +21.15 +$ +20.94 +$ +11.13 +Second Quarter +$ +24.71 +$ +20.13 +$ +25.54 +$ +18.03 +Third Quarter +$ +27.78 +$ +20.52 +$ +24.71 +$ +18.56 +Fourth Quarter +$ +31.59 +$ +24.04 +$ +27.71 +$ +20.45 +On February 21, 2018 , the last reported sales price of our common stock on the NYSE was $28.68 per share. +Dividend Policy +We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends on our common stock. During the years ended December 31, 2017 and 2016 , we did not pay dividends to holders of our common stock. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2017 . +Equity Compensation Plan Information +Plan Category +Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights +Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights +Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1) (2) +3,152,691 +$ +21.14 +2,356,467 +Equity compensation plans not approved by security holders +— +— +— +Total +3,152,691 +$ +21.14 +2,356,467 +__________________ +(1) +Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. +(2) +The Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015 and approved by our shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8 to the consolidated financial statements in this Annual Report. +54 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2012 through December 31, 2017 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +55 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2017 , the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs +Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2017 to October 31, 2017 +1,148 +$ +25.69 +— +— +November 1, 2017 to November 30, 2017 +327 +28.23 +— +— +December 1, 2017 to December 31, 2017 +910 +31.13 +— +— +Total +2,385 +$ +28.11 +— +— +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. +56 +Table of Contents +Item 6. Selected Financial Data. +The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2017 and selected consolidated balance sheet and cash flow data at December 31, 2017 , 2016 , 2015 , 2014 and 2013 . You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report. The financial information included in this Annual Report may not be indicative of our future results of operations, financial condition or cash flows. +Year Ended December 31, +2017 +2016 +2015 +2014 +2013 +(In thousands, except per share data) +Statement of operations data: +Revenues +Oil and natural gas revenues +$ +528,684 +$ +291,156 +$ +278,340 +$ +367,712 +$ +269,030 +Third-party midstream services revenue +10,198 +5,218 +1,864 +1,213 +207 +Realized (loss) gain on derivatives +(4,321 +) +9,286 +77,094 +5,022 +(909 +) +Unrealized gain (loss) on derivatives +9,715 +(41,238 +) +(39,265 +) +58,302 +(7,232 +) +Total revenues +544,276 +264,422 +318,033 +432,249 +261,096 +Expenses +Production taxes, transportation and processing +58,275 +43,046 +35,650 +33,172 +20,973 +Lease operating +67,313 +56,202 +54,704 +49,945 +37,971 +Plant and other midstream services operating +13,039 +5,389 +3,489 +1,408 +749 +Depletion, depreciation and amortization +177,502 +122,048 +178,847 +134,737 +98,395 +Accretion of asset retirement obligations +1,290 +1,182 +734 +504 +348 +Full-cost ceiling impairment +— +158,633 +801,166 +— +21,229 +General and administrative +66,016 +55,089 +50,105 +32,152 +20,779 +Total expenses +383,435 +441,589 +1,124,695 +251,918 +200,444 +Operating income (loss) +160,841 +(177,167 +) +(806,662 +) +180,331 +60,652 +Other income (expense) +Net gain (loss) on asset sales and inventory impairment +23 +107,277 +908 +— +(192 +) +Interest expense +(34,565 +) +(28,199 +) +(21,754 +) +(5,334 +) +(5,687 +) +Other income (expense) +3,551 +(4 +) +616 +132 +18 +Total other (expense) income +(30,991 +) +79,074 +(20,230 +) +(5,202 +) +(5,861 +) +Net income (loss) +138,007 +(97,057 +) +(679,524 +) +110,754 +45,094 +Net (income) loss attributable to non-controlling interest in subsidiaries +(12,140 +) +(364 +) +(261 +) +17 +— +Net income (loss) attributable to Matador Resources Company shareholders +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +$ +45,094 +Earnings (loss) per common share +Basic +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +$ +1.58 +$ +0.77 +Diluted +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +$ +1.56 +$ +0.77 +At December 31, +2017 +2016 +2015 +2014 +2013 +(In thousands) +Balance sheet data: +Cash and cash equivalents +$ +96,505 +$ +212,884 +$ +16,732 +$ +8,407 +$ +6,287 +Restricted cash +$ +5,977 +$ +1,258 +$ +44,357 +$ +609 +$ +— +Net property and equipment +$ +1,881,456 +$ +1,184,525 +$ +1,012,406 +$ +1,322,072 +$ +845,877 +Total assets +$ +2,145,690 +$ +1,464,665 +$ +1,140,861 +$ +1,434,490 +$ +890,330 +Current liabilities +$ +282,606 +$ +169,505 +$ +136,830 +$ +142,036 +$ +100,327 +Long-term liabilities +$ +605,538 +$ +603,715 +$ +515,072 +$ +425,913 +$ +221,079 +Total Matador Resources Company shareholders’ equity +$ +1,156,556 +$ +690,125 +$ +488,003 +$ +866,408 +$ +568,924 +57 +Table of Contents +Year Ended December 31, +2017 +2016 +2015 +2014 +2013 +(In thousands) +Other financial data: +Net cash provided by operating activities +$ +299,125 +$ +134,086 +$ +208,535 +$ +251,481 +$ +179,470 +Net cash used in investing activities +$ +(824,003 +) +$ +(405,640 +) +$ +(425,154 +) +$ +(570,531 +) +$ +(366,939 +) +Oil and natural gas properties capital expenditures +$ +(699,445 +) +$ +(379,067 +) +$ +(432,715 +) +$ +(560,849 +) +$ +(363,192 +) +Expenditures for midstream and other property and equipment +$ +(120,816 +) +$ +(74,845 +) +$ +(64,499 +) +$ +(9,152 +) +$ +(3,977 +) +Net cash provided by financing activities +$ +408,499 +$ +467,706 +$ +224,944 +$ +321,170 +$ +191,661 +Adjusted EBITDA attributable to Matador Resources Company shareholders +$ +336,063 +$ +157,892 +$ +223,138 +$ +262,943 +$ +191,771 +__________________ +(1) +Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “ – Non-GAAP Financial Measures” below. +Non-GAAP Financial Measures +We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +58 +Table of Contents +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2017 +2016 +2015 +2014 +2013 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net income (loss) attributable to Matador Resources Company shareholders +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +$ +45,094 +Net income (loss) attributable to non-controlling interest in subsidiaries +12,140 +364 +261 +(17 +) +— +Net income (loss) +138,007 +(97,057 +) +(679,524 +) +110,754 +45,094 +Interest expense +34,565 +28,199 +21,754 +5,334 +5,687 +Total income tax (benefit) provision +(8,157 +) +(1,036 +) +(147,368 +) +64,375 +9,697 +Depletion, depreciation and amortization +177,502 +122,048 +178,847 +134,737 +98,395 +Accretion of asset retirement obligations +1,290 +1,182 +734 +504 +348 +Full-cost ceiling impairment +— +158,633 +801,166 +— +21,229 +Unrealized (gain) loss on derivatives +(9,715 +) +41,238 +39,265 +(58,302 +) +7,232 +Stock-based compensation expense +16,654 +12,362 +9,450 +5,524 +3,897 +Net (gain) loss on asset sales and inventory impairment +(23 +) +(107,277 +) +(908 +) +— +192 +Consolidated Adjusted EBITDA +350,123 +158,292 +223,416 +262,926 +191,771 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries +(14,060 +) +(400 +) +(278 +) +17 +— +Adjusted EBITDA attributable to Matador Resources Company shareholders +$ +336,063 +$ +157,892 +$ +223,138 +$ +262,943 +$ +191,771 +Year Ended December 31, +2017 +2016 +2015 +2014 +2013 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities +$ +299,125 +$ +134,086 +$ +208,535 +$ +251,481 +$ +179,470 +Net change in operating assets and liabilities +25,058 +(1,809 +) +(8,980 +) +5,978 +6,210 +Interest expense, net of non-cash portion +34,097 +27,051 +20,902 +5,334 +5,687 +Current income tax (benefit) provision +(8,157 +) +(1,036 +) +2,959 +133 +404 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries +(14,060 +) +(400 +) +(278 +) +17 +— +Adjusted EBITDA attributable to Matador Resources Company shareholders +$ +336,063 +$ +157,892 +$ +223,138 +$ +262,943 +$ +191,771 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +Overview +We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, +59 +Table of Contents +development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +2017 Operational Highlights +During the year ended December 31, 2017 , we completed and began producing oil and natural gas from 65 gross (56.1 net) operated and 21 gross (3.5 net) non-operated wells in the Delaware Basin and from five gross (5.0 net) operated and three gross (0.8 net) non-operated Eagle Ford shale wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017 , although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that began producing in 2017 . +During 2017 , we continued our focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We began 2017 operating four drilling rigs in the Delaware Basin and continued to do so throughout the first quarter of 2017. In late April 2017, we added a fifth drilling rig in the Delaware Basin, operating this rig in our Rustler Breaks asset area. During the third quarter of 2017, we took delivery of a sixth drilling rig for the initial purpose of drilling two commercial salt water disposal wells in the Rustler Breaks asset area for San Mateo. Between August and October 2017, we used this rig to drill the two salt water disposal wells, both of which were completed and were operational as of February 21, 2018 . San Mateo has elected to commission the drilling and completion of two additional commercial salt water disposal wells and the construction of associated commercial salt water disposal facilities in the Rustler Breaks asset area, which, when completed, will result in a total of five commercial salt water disposal wells in the Rustler Breaks asset area. We anticipated spudding the fourth salt water disposal well at Rustler Breaks prior to the end of 2017, but due to a delay in securing the water injection permit for this well, we elected to move the sixth rig to the Antelope Ridge asset area to begin drilling our first oil and natural gas wells in that area. We drilled two oil and natural gas wells in the Antelope Ridge asset area during the fourth quarter of 2017. At December 31, 2017 and February 21, 2018 , we were operating six drilling rigs in the Delaware Basin. +The vast majority of our 2017 capital expenditures were directed to the delineation and development of our leasehold position in the Delaware Basin, to the development of certain midstream assets to support our operations there and to the acquisition of additional leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to our five-well drilling and completion program in the Eagle Ford shale in South Texas, which was completed early in the third quarter of 2017, and to our participation in several non-operated wells drilled and completed in the Eagle Ford and Haynesville shales throughout 2017, as noted above. Our 2017 capital expenditures for drilling, completing and equipping wells were approximately $493 million . +We increased our leasehold position significantly in the Delaware Basin during 2017, acquiring 25,100 net acres in the Delaware Basin, including a small volume of associated production. Excluding the value of the production acquired, this acreage was added for a weighted average cost of between approximately $7,000 and $8,000 per net acre. At December 31, 2017 , we held approximately 199,600 gross ( 114,000 net) acres in the Permian Basin in Southeast New Mexico and West Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. +Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, an increase of 40% as compared to 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, for the year ended December 31, 2016 . Our average daily oil production in 2017 of 21,510 Bbl of oil per day increased 54% , as compared to an average daily oil production of 13,924 Bbl of oil per day in 2016 . This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, but also to production from five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Our average daily natural gas production of 104.6 MMcf per day for the year ended December 31, 2017 increased 25% from 83.3 MMcf per day for the year ended December 31, 2016 . This increase in natural gas production was primarily attributable to increased natural gas production associated with our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 55% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2017 , as compared to 50% for the year ended December 31, 2016 . +For the year ended December 31, 2017 , our oil and natural gas revenues were $528.7 million , an increase of 82% from oil and natural gas revenues of $291.2 million for the year ended December 31, 2016 . Our oil revenues and natural gas revenues increased 84% and 75% to approximately $386.9 million and $141.8 million , respectively, as compared to $209.9 million and $81.2 million , respectively, for the year ended December 31, 2016 . The increase in oil and natural gas revenues resulted from (i) the increases in oil and natural gas production for the year ended December 31, 2017 as noted above and (ii) higher realized weighted average oil and natural gas prices of $49.28 per Bbl and $3.72 per Mcf in 2017 , respectively, as compared to $41.19 per Bbl and $2.66 per Mcf in 2016 , respectively. +60 +Table of Contents +We reported net income attributable to Matador Resources Company shareholders of approximately $125.9 million , or $1.23 per diluted common share, on a GAAP basis for the year ended December 31, 2017 , as compared to a net loss of $97.4 million , or $1.07 per diluted common share, for the year ended December 31, 2016 . Adjusted EBITDA for the year ended December 31, 2017 was $336.1 million , as compared to Adjusted EBITDA of $157.9 million reported for the year ended December 31, 2016 . Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +At December 31, 2017 , our estimated total proved oil and natural gas reserves were 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, with a Standardized Measure of $1.26 billion and a PV-10 of $1.33 billion . At December 31, 2016 , our estimated total proved oil and natural gas reserves were 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, with a Standardized Measure of $575.0 million and a PV-10 of $581.5 million . Our estimated total proved reserves of 152.8 million BOE at December 31, 2017 represented a 44% year-over-year increase, as compared to 105.8 million BOE at December 31, 2016 . Our estimated proved oil reserves of 86.7 million Bbl at December 31, 2017 increased 52% , as compared to 57.0 million Bbl at December 31, 2016 . Our proved oil and natural gas reserves in the Delaware Basin increased 62% to 129.0 million BOE at December 31, 2017 , as compared to 79.4 million BOE at December 31, 2016 , as a result of our ongoing delineation and development operations in the Delaware Basin. At December 31, 2017 , approximately 84% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 65% to 77.5 million Bbl at December 31, 2017 , as compared to 46.9 million Bbl at December 31, 2016 . Proved oil reserves comprised 57% of our total proved reserves at December 31, 2017 , as compared to 54% at December 31, 2016 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” +2017 Midstream Joint Venture +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection with the formation of San Mateo. As of January 31, 2018, we had earned an additional $14.7 million in performance incentives to be paid to us by Five Point in the first quarter of 2018, and we may earn up to an additional $58.8 million in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +2018 Strategic Relationship with Plains +On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains to gather and transport crude oil for the Company and third-party customers in and around the Rustler Breaks asset area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase our oil production in the Rustler Breaks asset area and in the Wolf asset area in Loving County, Texas. +61 +Table of Contents +2018 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2018 . We plan to operate six contracted drilling rigs drilling primarily oil and natural gas wells in the Delaware Basin throughout 2018 . One of the six rigs is also expected to drill at least two additional salt water disposal wells in the Rustler Breaks asset area for San Mateo during 2018. As a result, we expect that this particular rig will spend only approximately three-quarters of the year drilling oil and natural gas wells. Our 2018 estimated capital expenditure budget consists of $530 to $570 million for drilling, completions, facilities and infrastructure and $70 to $90 million for midstream capital expenditures, which reflects our 51% share of San Mateo’s estimated 2018 capital expenditures. Substantially all of our 2018 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2018 Delaware Basin drilling program will focus on the continued development of the Rustler Breaks and Wolf asset areas and the further delineation and development of the Antelope Ridge, Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested intervals in the Rustler Breaks and Wolf asset areas during 2018 as well. +We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2018 . These expenditures are opportunity-specific and per-acre prices can vary significantly based on the prospect. As a result, it is difficult to estimate these 2018 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2018 . +At December 31, 2017 , we had $96.5 million in cash (excluding restricted cash) and $397.9 million in undrawn borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit). As a result, we expect to fund our capital expenditures for 2018 through a combination of cash on hand, operating cash flows, performance incentives in connection with the formation of San Mateo that were earned in the first quarter of 2018 and borrowings under our Credit Agreement (assuming availability under our borrowing base). We may also consider funding a portion of our 2018 capital expenditures through borrowings under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. The aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs of our midstream activities, other opportunities that may become available to us and our ability to obtain capital. +62 +Table of Contents +Revenues +Our revenues are derived primarily from the sale of oil, natural gas and NGL production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or NGL prices. +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2017 +2016 +2015 +Operating Data: +Revenues (in thousands): (1) +Oil +$ +386,865 +$ +209,908 +$ +203,355 +Natural gas +141,819 +81,248 +74,985 +Total oil and natural gas revenues +528,684 +291,156 +278,340 +Third-party midstream services revenues +10,198 +5,218 +1,864 +Realized (loss) gain on derivatives +(4,321 +) +9,286 +77,094 +Unrealized gain (loss) on derivatives +9,715 +(41,238 +) +(39,265 +) +Total revenues +$ +544,276 +$ +264,422 +$ +318,033 +Net Production Volumes: (1) +Oil (MBbl) +7,851 +5,096 +4,492 +Natural gas (Bcf) +38.2 +30.5 +27.7 +Total oil equivalent (MBOE) (2) +14,212 +10,180 +9,109 +Average daily production (BOE/d) (2) +38,936 +27,813 +24,955 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +49.28 +$ +41.19 +$ +45.27 +Oil, with realized derivatives (per Bbl) +$ +48.81 +$ +42.34 +$ +59.13 +Natural gas, without realized derivatives (per Mcf) +$ +3.72 +$ +2.66 +$ +2.71 +Natural gas, with realized derivatives (per Mcf) +$ +3.70 +$ +2.78 +$ +3.24 +________________ +(1) +We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2017 as Compared to Year Ended December 31, 2016 +Oil and natural gas revenues . Our oil and natural gas revenues increase d $237.5 million to $528.7 million , or 82% , for the year ended December 31, 2017 , as compared to $291.2 million for the year ended December 31, 2016 . Our oil revenues increase d $177.0 million , or 84% , to $386.9 million for the year ended December 31, 2017 , as compared to $209.9 million for the year ended December 31, 2016 . The increase in oil revenues resulted from (i) a higher weighted average oil price realized for the year ended December 31, 2017 of $49.28 per Bbl, as compared to $41.19 per Bbl realized for the year ended December 31, 2016 , and (ii) the 54% increase in our oil production to 7.9 million Bbl of oil for the year ended December 31, 2017 , or about 21,510 Bbl of oil per day, as compared to 5.1 million Bbl of oil, or about 13,924 Bbl of oil per day, for the year ended December 31, 2016 . This increase d oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, but also to production from the five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Our natural gas revenues increase d by $60.6 million , or 75% , to $141.8 million for the year ended December 31, 2017 , as compared to $81.2 million for the year ended December 31, 2016 . The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price realized for the year ended December 31, 2017 of $3.72 per Mcf, as compared to $2.66 per Mcf realized for the year ended December 31, 2016 , and (ii) the 25% increase in our natural gas production to 38.2 Bcf for the year ended December 31, 2017 , as compared to 30.5 Bcf for the year ended December 31, 2016 . The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. +Third-party midstream services revenues. Our third-party midstream services revenues increased $5.0 million to $10.2 million , or 95% , for the year ended December 31, 2017 , as compared to $5.2 million for the year ended December 31, 2016 . Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately $7.9 million for the year ended December 31, 2017 , as compared to $3.6 million for the year ended December 31, 2016 , due to (i) the Black River Processing Plant being placed into service in the second half of 2016 and operating for the full year in 2017 and (ii) increased natural gas production in our Rustler Breaks and +63 +Table of Contents +Wolf asset areas. The remaining increase in our third-party midstream services revenues was primarily attributable to the increase in third-party salt water disposal revenue to approximately $2.1 million during the year ended December 31, 2017 , as compared to approximately $1.6 million for the year ended December 31, 2016 , primarily due to an increase in salt water gathering and disposal at our facilities in the Rustler Breaks and Wolf asset areas in 2017. +Realized (loss) gain on derivatives . Our realized net loss on derivatives was $4.3 million for the year ended December 31, 2017 , as compared to a net gain of approximately $9.3 million for the year ended December 31, 2016 . We realized net loss es of $3.7 million and $0.6 million from our oil and natural gas costless collar contracts, respectively, for the year ended December 31, 2017 , resulting from oil and natural gas prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts. We realized net gain s of $5.9 million and $3.4 million from our oil and natural gas derivative contracts, respectively, for the year ended December 31, 2016 , resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. We realized an average loss on our oil derivatives of approximately $0.47 per Bbl produced during the year ended December 31, 2017 , as compared to an average gain of $1.15 per Bbl produced during the year ended December 31, 2016 . Our total oil volumes hedged for the year ended December 31, 2017 represented 59% of our total oil production, as compared to 50% of our total oil production the year ended December 31, 2016 . We realized an average loss on our natural gas and NGL derivatives of approximately $0.02 per Mcf produced during the year ended December 31, 2017 , as compared to an average gain of approximately $0.12 per Mcf produced for the year ended December 31, 2016 . Our total natural gas volumes hedged for the year ended December 31, 2017 represented 63% of our total natural gas production, as compared to 44% of our total natural gas production for the year ended December 31, 2016 . +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $9.7 million for the year ended December 31, 2017 , as compared to an unrealized loss of $41.2 million for the year ended December 31, 2016 . During the year ended December 31, 2017 , the aggregate net fair value of our open oil and natural gas derivatives contracts increase d from a net liability of approximately $25.0 million to a net liability of approximately $15.2 million , resulting in an unrealized gain on derivatives of approximately $9.7 million for the year ended December 31, 2017 . During the year ended December 31, 2016 , the aggregate net fair value of our open oil and natural gas derivative contracts decreased from a net asset of approximately $16.3 million to a net liability of approximately $25.0 million , resulting in an unrealized loss on derivatives of approximately $41.2 million for the year ended December 31, 2016 . +Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015 +Oil and natural gas revenues . Our oil and natural gas revenues increased $12.8 million to $291.2 million, or an increase of 5%, for the year ended December 31, 2016, as compared to $278.3 million for the year ended December 31, 2015. Our oil revenues increased $6.6 million, or an increase of 3%, to $209.9 million for the year ended December 31, 2016, as compared to $203.4 million for the year ended December 31, 2015. The increase in oil revenues resulted from the 13% increase in our oil production to 5.1 million Bbl of oil for the year ended December 31, 2016, or about 13,924 Bbl of oil per day, as compared to 4.5 million Bbl of oil, or about 12,306 Bbl of oil per day, for the year ended December 31, 2015. This increased oil production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the Eagle Ford shale, where we had not drilled any new operated wells since the second quarter of 2015. The increase in oil revenues was partially impacted by a lower weighted average oil price realized for the year ended December 31, 2016 of $41.19 per Bbl, as compared to $45.27 per Bbl realized for the year ended December 31, 2015. Our natural gas revenues increased $6.3 million, or an increase of 8%, to $81.2 million for the year ended December 31, 2016, as compared to $75.0 million for the year ended December 31, 2015. The increase in natural gas revenues resulted from the 10% increase in our natural gas production to 30.5 Bcf for the year ended December 31, 2016, as compared to 27.7 Bcf for the year ended December 31, 2015. The increased natural gas production was primarily attributable to our ongoing delineation and development drilling in the Delaware Basin, which offset declining natural gas production in the Eagle Ford and Haynesville shales where we had significantly reduced our activity since late 2014 and early 2015. The increase in natural gas revenues was partially impacted by a lower weighted average natural gas price realized for the year ended December 31, 2016 of $2.66 per Mcf, as compared to $2.71 per Mcf realized for the year ended December 31, 2015. +Third-party midstream services revenues. During the third quarter of 2016, our midstream operations became a reportable business segment under GAAP. Our third-party midstream services revenues were previously included in other income. Third-party midstream services revenues are primarily those revenues from midstream operations related to third parties, including working interest owners in our operated wells; all midstream services revenues associated with our production are eliminated in consolidation. Our third-party midstream services revenues increased to $5.2 million, or an increase of almost three-fold, for the year ended December 31, 2016, as compared to $1.9 million for the year ended December 31, 2015. This increase was primarily attributable to a significant increase in third-party salt water disposal revenue to approximately $1.6 million for the year ended December 31, 2016, as compared to $0.2 million for the year ended December 31, 2015, due to increased salt water disposal at our facilities in the Wolf asset area in 2016. The remaining increase was primarily attributable to third-party natural gas gathering and processing fees of $3.6 million for the year ended December 31, 2016, as compared to $1.7 million for the +64 +Table of Contents +year ended December 31, 2015, including natural gas processing at the Black River Processing Plant, which began operating in August 2016. +Realized gain on derivatives . Our realized net gain on derivatives was $9.3 million for the year ended December 31, 2016, as compared to a realized net gain of $77.1 million for the year ended December 31, 2015. We realized net gains of $5.9 million and $3.4 million from our oil and natural gas derivative contracts, respectively, for the year ended December 31, 2016 resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. Our realized net gain on derivatives was $77.1 million for the year ended December 31, 2015. We realized net gains of $62.3 million, $12.7 million and $2.2 million from our oil, natural gas and NGL derivative contracts, respectively, for the year ended December 31, 2015 resulting from oil and natural gas prices being below the floor prices of most of our oil and natural gas costless collar contracts and NGL prices being below the fixed prices of all of our swap contracts. We realized an average gain of approximately $2.29 per Bbl hedged on all of our open oil costless collar contracts during the year ended December 31, 2016, as compared to an average gain of $22.89 per Bbl hedged for the year ended December 31, 2015. Our oil volumes hedged for the year ended December 31, 2016 were also 6% lower as compared to the year ended December 31, 2015. We realized an average gain of approximately $0.26 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2016, as compared to an average gain of approximately $0.73 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2015. Our total natural gas volumes hedged for the year ended December 31, 2016 were also 23% lower than the total natural gas volumes hedged for the year ended December 31, 2015. We realized an average gain of approximately $1.15 per Bbl produced on our open oil derivative contracts during the year ended December 31, 2016, as compared to an average gain of $13.86 per Bbl produced for the year ended December 31, 2015. Our total oil volumes hedged for the year ended December 31, 2016 represented 50% of our total oil production for the year ended December 31, 2016, as compared to 61% of our total oil production for the year ended December 31, 2015. We realized an average gain of approximately $0.12 per Mcf produced on our open natural gas derivative contracts during the year ended December 31, 2016, as compared to an average gain of approximately $0.53 per Mcf produced on our open natural gas costless collar contracts during the year ended December 31, 2015. Our total natural gas volumes hedged for the year ended December 31, 2016 represented 44% of our total natural gas production for the year ended December 31, 2016, as compared to 63% of our total natural gas production for the year ended December 31, 2015. +Unrealized gain (loss) on derivatives. Our unrealized net loss on derivatives was $41.2 million for the year ended December 31, 2016, as compared to an unrealized net loss of $39.3 million for the year ended December 31, 2015. During the year ended December 31, 2016, the net fair value of our open oil and natural gas derivatives contracts decreased to a net liability of approximately $25.0 million from a net asset of $16.3 million for the year ended December 31, 2015, resulting in an unrealized net loss on derivatives of $41.2 million for the year ended December 31, 2016. During the year ended December 31, 2016, the net fair value of our open oil and natural gas derivative contracts decreased $32.2 million and $9.1 million, respectively, due to the increase in the underlying oil and natural gas futures prices at December 31, 2016, as well as realized gains from oil and natural gas derivative contracts settled during the year ended December 31, 2016. +65 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2017 +2016 +2015 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing +$ +58,275 +$ +43,046 +$ +35,650 +Lease operating +67,313 +56,202 +54,704 +Plant and other midstream services operating +13,039 +5,389 +3,489 +Depletion, depreciation and amortization +177,502 +122,048 +178,847 +Accretion of asset retirement obligations +1,290 +1,182 +734 +Full-cost ceiling impairment +— +158,633 +801,166 +General and administrative +66,016 +55,089 +50,105 +Total expenses +383,435 +441,589 +1,124,695 +Operating income (loss) +160,841 +(177,167 +) +(806,662 +) +Other income (expense): +Net gain on asset sales and inventory impairment +23 +107,277 +908 +Interest expense +(34,565 +) +(28,199 +) +(21,754 +) +Other income (expense) +3,551 +(4 +) +616 +Total other (expense) income +(30,991 +) +79,074 +(20,230 +) +Income (loss) before income taxes +129,850 +(98,093 +) +(826,892 +) +Total income tax benefit +(8,157 +) +(1,036 +) +(147,368 +) +Net income attributable to non-controlling interest in subsidiaries +(12,140 +) +(364 +) +(261 +) +Net income (loss) attributable to Matador Resources Company shareholders +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +Expenses per BOE: +Production taxes, transportation and processing +$ +4.10 +$ +4.23 +$ +3.91 +Lease operating +$ +4.74 +$ +5.52 +$ +6.01 +Plant and other midstream services operating +$ +0.92 +$ +0.53 +$ +0.38 +Depletion, depreciation and amortization +$ +12.49 +$ +11.99 +$ +19.63 +General and administrative +$ +4.65 +$ +5.41 +$ +5.50 +Year Ended December 31, 2017 as Compared to Year Ended December 31, 2016 +Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increase d by approximately $15.2 million to $58.3 million , or 35% , for the year ended December 31, 2017 , as compared to $43.0 million for the year ended December 31, 2016 . The increase in production taxes, transportation and processing expenses on an absolute basis was primarily attributable to the $16.4 million increase in our production taxes to $33.0 million for the year ended December 31, 2017 , as compared to $16.6 million for the year ended December 31, 2016 , primarily due to the $237.5 million increase in oil and natural gas revenues for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . In addition, the production tax rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production becomes attributable to New Mexico, we expect our production tax expenses to increase. The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to $25.3 million for the year ended December 31, 2017 , as compared to transportation and processing expenses of $26.5 million for the year ended December 31, 2016 . This decrease of $1.2 million was primarily due to the start-up in late August 2016 of the Black River Processing Plant, which processes most of the natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico, and which was operational for the full year in 2017. On a unit-of-production basis, our production taxes, transportation and processing expenses decrease d to $4.10 per BOE for the year ended December 31, 2017 , as compared to $4.23 per BOE for the year ended December 31, 2016 , due not only to the decreased transportation and processing charges attributable to the start-up of the Black River Processing Plant, but also to the 40% increase in total oil equivalent production during in the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . +Lease operating expenses. Our lease operating expenses increase d by $11.1 million to $67.3 million , or 20% , for the year ended December 31, 2017 , as compared to $56.2 million for the year ended December 31, 2016 . The increase in lease operating expenses on an absolute basis for the year ended December 31, 2017 was primarily attributable to an increase in the costs of services and equipment related to the increased number of wells we operated during the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , resulting from our increased delineation and development drilling activities in the Delaware Basin. Our lease operating expenses on a unit-of-production basis decrease d 14% to $4.74 per BOE for the year ended December 31, 2017 , as compared to $5.52 per BOE for the year ended December 31, 2016 . The decrease in lease +66 +Table of Contents +operating expenses on a unit-of-production basis for the year ended December 31, 2017 was attributable to (i) increased efficiencies as more salt water was gathered by pipeline to San Mateo’s disposal facilities in the Delaware Basin, (ii) decreased workover expenses, (iii) decreased salt water disposal and chemical costs associated with our Eagle Ford operations and (iv) a 40% increase in total oil equivalent production in 2017 , as compared to 2016 . +Plant and other midstream services operating. Our plant and other midstream services operating expenses increase d by $7.7 million to $13.0 million , an increase of 142% , for the year ended December 31, 2017 , as compared to $5.4 million for the year ended December 31, 2016 . This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $6.8 million for the year ended December 31, 2017 , as compared to $3.6 million for the year ended December 31, 2016 , and (ii) increased expenses associated with the Black River Processing Plant, which began operating in August 2016, of $4.6 million for the year ended December 31, 2017 , as compared to $0.7 million for the year ended December 31, 2016 . +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d by $55.5 million to $177.5 million , or 45% , for the year ended December 31, 2017 , as compared to $122.0 million for the year ended December 31, 2016 . On a unit-of-production basis, our depletion, depreciation and amortization expenses increase d 4% to $12.49 per BOE for the year ended December 31, 2017 , as compared to $11.99 per BOE for the year ended December 31, 2016 . The increase in both our total depletion, depreciation and amortization and unit-of-production depletion, depreciation and amortization expenses was primarily attributable to (i) increased depreciation expenses of approximately $5.2 million for the year ended December 31, 2017 , as compared to $2.7 million for the year ended December 31, 2016 , associated with our new midstream assets placed into service in 2017 and (ii) higher estimated future development costs associated with proved undeveloped oil and natural gas reserves at December 31, 2017 , both of which were offset by the increase in the Company’s total proved oil and natural gas reserves between the respective periods. +Full-cost ceiling impairment. We recorded no impairment charge to the net capitalized costs of our oil and natural gas properties for the year ended December 31, 2017 . We recorded an impairment charge of $158.6 million to the net capitalized costs of our oil and natural gas properties for the year ended December 31, 2016 . +General and administrative. Our general and administrative expenses increase d $10.9 million to $66.0 million , an increase of 20% , for the year ended December 31, 2017 , as compared to $55.1 million for the year ended December 31, 2016 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses of approximately $10.4 million associated with additional employees joining the Company to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of the continued growth of the Company and to the $4.3 million increase in non-cash stock-based compensation expense to $16.7 million for the year ended December 31, 2017 , as compared to $12.4 million for the year ended December 31, 2016 . The increase in our non-cash stock-based compensation was attributable to the increased expense related to the vesting of awards granted from 2013 through 2017 and the granting of new awards during 2017, as well as a change in the vesting schedule applicable to equity awards granted to our board of directors resulting in a $1.5 million one-time stock-based compensation expense. Our general and administrative expenses decrease d 14% on a unit-of-production basis to $4.65 per BOE for the year ended December 31, 2017 , as compared to $5.41 per BOE for the year ended December 31, 2016 , primarily due to the 40% increase in total oil equivalent production between the respective periods. +Net gain on asset sales and inventory impairment. We recorded a net gain of $23,000 on asset sales and inventory impairment for the year ended December 31, 2017 , as compared to a net gain of $107.3 million for the year ended December 31, 2016 related to the sale of our wholly-owned subsidiary that owned the Loving County Processing System. See below and Note 5 to the consolidated financial statements in this Annual Report for more information on this sale. +Interest expense. For the year ended December 31, 2017 , we incurred total interest expense of approximately $41.9 million . We capitalized approximately $7.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2017 and expensed the remaining $34.6 million to operations. For the year ended December 31, 2016 , we incurred total interest expense of approximately $31.9 million . We capitalized $3.7 million of our interest expense on certain qualifying projects for the year ended December 31, 2016 and expensed the remaining $28.2 million to operations. The increase in total interest expense for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , was primarily attributable to an increase in our average debt outstanding. In December 2016, we issued an additional $175.0 million of 6.875% senior notes due 2023, increasing our total senior notes outstanding to $575.0 million from $400.0 million . As a result, we incurred interest on the entire $575.0 million in senior notes outstanding during the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , when the $575.0 million of senior notes were outstanding for only a portion of December 2016. +67 +Table of Contents +Total income tax (benefit) provision . Our deferred tax assets exceeded our deferred tax liabilities at December 31, 2017 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. We established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015, and we retained a full valuation allowance at December 31, 2017 due to uncertainties regarding the future realization of our deferred tax assets. The current tax benefit of $8.2 million for the year ended December 31, 2017 was primarily the result of the Tax Cuts and Jobs Act, under which corporate alternative minimum taxes were repealed. As a result, corporate alternative minimum tax carryforwards will be refunded. The total income tax expense for the years ended December 31, 2017 and 2016 differed from amounts computed by applying the U.S. federal statutory tax rate to the pre-tax loss due primarily to recording a valuation allowance against the net deferred tax asset position as a result of the full-cost ceiling impairments recorded for the years ended December 31, 2016 and 2015. +Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015 +Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased $7.4 million to $43.0 million, an increase of 21%, for the year ended December 31, 2016, as compared to $35.7 million for the year ended December 31, 2015. On a unit-of-production basis, our production taxes, transportation and processing expenses increased 8% to $4.23 per BOE for the year ended December 31, 2016, as compared to $3.91 per BOE for the year ended December 31, 2015. The increase in production taxes, transportation and processing expenses was primarily attributable to higher transportation and processing expenses of $26.5 million for the year ended December 31, 2016, as compared to transportation and processing expenses of $22.4 million for the year ended December 31, 2015. This increase of $4.1 million was primarily due to the increase in natural gas production in the Delaware Basin as a percentage of our total natural gas production for the year ended December 31, 2016, as compared to the year ended December 31, 2015. Natural gas transportation and processing expenses are higher in the Delaware Basin, as compared to the Eagle Ford shale, as the natural gas gathering and processing infrastructure had yet to meet the demand for these services due to the increased drilling activity in the Delaware Basin over the last few years. +Our production taxes increased $3.4 million to $16.6 million for the year ended December 31, 2016, as compared to $13.2 million for the year ended December 31, 2015, primarily due to the 5% increase in oil and natural gas revenues for the year ended December 31, 2016, as compared to the year ended December 31, 2015. In addition to the increase in production taxes attributable to the 5% increase in oil and natural gas revenues, the production tax rates in New Mexico are higher than production tax rates in Texas. +Lease operating expenses. Our lease operating expenses increased $1.5 million to $56.2 million, an increase of 3%, for the year ended December 31, 2016, as compared to $54.7 million for the year ended December 31, 2015. Our lease operating expenses per unit of production decreased 8% to $5.52 per BOE for the year ended December 31, 2016, as compared to $6.01 per BOE for the year ended December 31, 2015. Our total oil and natural gas production increased 12% to approximately 10.2 million BOE for the year ended December 31, 2016 from approximately 9.1 million BOE for the year ended December 31, 2015. The decrease achieved in lease operating expenses on a unit-of-production basis was primarily attributable to several key factors, including (i) decreased field supervisory costs as a number of third-party contractors became full-time employees during the second quarter of 2016, (ii) decreased costs associated with our Eagle Ford operations, including supervisory, salt water disposal and chemical costs and (iii) increased oil equivalent production as compared to the year ended December 31, 2015. This decrease was partially offset by (x) increased salt water disposal costs attributable to increased operations in the Rustler Breaks asset area and (y) increased workover expenses in the Wolf asset area. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $1.9 million to $5.4 million, an increase of 54%, for the year ended December 31, 2016, as compared to $3.5 million for the year ended December 31, 2015. This increase was primarily attributable to the expenses associated with our salt water disposal operations of $3.6 million for the year ended December 31, 2016, as compared to $2.2 million for the year ended December 31, 2015. The remaining increase was primarily attributable to expenses associated with the Black River Processing Plant, which began operating in August 2016. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $56.8 million to $122.0 million, a decrease of 32%, for the year ended December 31, 2016, as compared to $178.8 million for the year ended December 31, 2015. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 39% to $11.99 per BOE for the year ended December 31, 2016, as compared to $19.63 per BOE for the year ended December 31, 2015. The decrease in our total depletion, depreciation and amortization expenses resulted primarily from (i) higher total proved reserves of 105.8 million BOE, or an increase of 24%, at December 31, 2016, as compared to total proved reserves of 85.1 million BOE at December 31, 2015, (ii) the decreased cost on a unit-of-production basis associated with wells drilled in 2016, as compared to prior periods and (iii) the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2015 and 2016. This increase in total proved oil and natural gas reserves was primarily attributable to the continued delineation and development of our acreage in the Delaware Basin. +68 +Table of Contents +Full-cost ceiling impairment. Due primarily to the continued decline in oil and natural gas prices during the first half of 2016, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling. As a result, we recorded an impairment charge of $158.6 million, exclusive of tax effect, for the year ended December 31, 2016 to our net capitalized costs. This charge is reflected in our statement of operations for the year ended December 31, 2016, with the related deferred income tax credit recorded net of a valuation allowance. These full-cost impairment charges for the year ended December 31, 2016 were realized in the first two quarters of the year. Since that time, oil and natural gas prices improved and as a result, no full-cost ceiling impairment charges were recorded in the third and fourth quarters of 2016. +Due primarily to the sharp decline in oil and natural gas prices during 2015, at December 31, 2015, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling. As a result, we recorded an impairment charge of $801.2 million, exclusive of tax effect, to our net capitalized costs. This charge is reflected in our statement of operations for the year ended December 31, 2015, with the related deferred income tax credit recorded net of a valuation allowance. +General and administrative. Our general and administrative expenses increased $5.0 million to $55.1 million, an increase of 10%, for the year ended December 31, 2016, as compared to $50.1 million for the year ended December 31, 2015. The increase in our general and administrative expenses was primarily attributable to increased payroll expenses associated with additional employees joining the Company during the year ended December 31, 2016 to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of the continued growth of the Company. The remaining increase is largely due to a $2.9 million increase in non-cash stock-based compensation expense to $12.4 million for the year ended December 31, 2016, as compared to $9.5 million for the year ended December 31, 2015. The increase in our non-cash stock-based compensation expense was attributable to the increased expense related to the continued vesting of awards granted from 2012 through 2016. Our general and administrative expenses decreased 2% on a unit-of-production basis to $5.41 per BOE for the year ended December 31, 2016, as compared to $5.50 per BOE for the year ended December 31, 2015. +Net gain on asset sales and inventory impairment. We recorded a net gain of $107.3 million on asset sales and inventory impairment for the year ended December 31, 2016, as compared to $0.9 million for the year ended December 31, 2015. On October 1, 2015, we completed the sale of our wholly-owned subsidiary that owned the Loving County Processing System to EnLink. The Loving County Processing System included the Wolf Processing Plant and approximately six miles of high pressure gathering pipeline that connects our natural gas gathering system to the Wolf Processing Plant. +Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and we received net proceeds of approximately $139.8 million, after deducting customary purchase price adjustments of approximately $3.6 million. Due to the terms of the Wolf Gathering Agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as a deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and processing agreement. See Note 5 to the consolidated financial statements in this Annual Report for more information on this agreement. +During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of the new plant, EnLink began processing our natural gas at the new plant. As such, the gathering and processing agreement was no longer considered a lease, and accordingly the Company recognized the remaining unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016. +Interest expense. For the year ended December 31, 2016, we incurred total interest expense of approximately $31.9 million. We capitalized approximately $3.7 million of our interest expense on certain qualifying projects for the year ended December 31, 2016 and expensed the remaining $28.2 million to operations. For the year ended December 31, 2015, we incurred total interest expense of approximately $25.7 million. We capitalized approximately $3.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2015 and expensed the remaining $21.8 million to operations. The increase in total interest expense of $6.2 million for the year ended December 31, 2016, as compared to the year ended December 31, 2015, was attributable to an increase in both the average debt outstanding and the coupon rate of 6.875% for the senior notes issued in 2015 and late 2016, as compared to the lower effective interest rates incurred on borrowings under our Credit Agreement. In December 2016, we used a portion of the net proceeds from the December 2016 senior notes and equity offerings to repay a total of $120.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2016, we had no outstanding borrowings under our Credit Agreement, $0.8 million in outstanding letters of credit and $575.0 million in outstanding senior notes. +69 +Table of Contents +Total income tax (benefit) provision . Our deferred tax assets exceeded our deferred tax liabilities at December 31, 2016 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in 2016 and 2015. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015. We retained a full valuation allowance at December 31, 2016 due to uncertainties regarding the future realization of our deferred tax assets. The current tax benefit of $1.0 million for the year ended December 31, 2016 was primarily attributable to a refund due from the Internal Revenue Service. The total income tax expense for the year ended December 31, 2016 differed from amounts computed by applying the U.S. federal statutory tax rate to the pre-tax loss due primarily to the recording of a valuation allowance against the net deferred tax asset position as a result of the full-cost ceiling impairments recorded for the years ended December 31, 2016 and 2015. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2018 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditure requirements through 2018 through a combination of cash on hand, operating cash flows, performance incentives in connection with the formation of San Mateo that were earned in the first quarter of 2018 and borrowings under our Credit Agreement (assuming availability under our borrowing base). We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows. +At December 31, 2017 , we had cash totaling approximately $96.5 million and restricted cash totaling approximately $6.0 million , most of which is associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with other of our cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +On October 25, 2017 , the lenders party to our Credit Agreement increased our borrowing base from $450.0 million to $525.0 million , and the maximum facility amount remained at $500.0 million . We elected to keep the borrowing commitment at $400.0 million . This October 2017 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment. At December 31, 2017 and February 21, 2018 , the borrowing base under our Credit Agreement remained $525.0 million . At both dates, we had no outstanding borrowings and approximately $2.1 million in outstanding letters of credit under the Credit Agreement, and we had $575.0 million of outstanding senior notes. +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection with the formation of San Mateo. As of January 31, 2018, we had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018, and we may earn up to an additional $58.8 million in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +On October 10, 2017, we completed a public offering of 8.0 million shares of our common stock, receiving proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, acreage acquisitions and general corporate purposes, including to fund a portion of our current and future capital expenditures. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2018 . We plan to operate six contracted drilling rigs in the Delaware Basin throughout 2018 . One of the six rigs is also expected to drill at least two additional salt water disposal wells in the Rustler Breaks asset area for San Mateo during 2018. Our 2018 estimated capital expenditure budget consists of $530 to $570 million for drilling, completions, facilities and infrastructure and $70 to $90 million for midstream capital expenditures, which represents our 51% share of San Mateo’s 2018 capital expenditures. Substantially all of our 2018 estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2018 Delaware Basin drilling program will focus on the continued development of the Wolf and Rustler Breaks asset areas and the further delineation and development of the Antelope Ridge, Jackson Trust, +70 +Table of Contents +Ranger/Arrowhead and Twin Lakes asset areas, although we also anticipate continuing to delineate previously untested intervals in the Wolf and Rustler Breaks asset areas during 2018 as well. +We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2018. These expenditures are opportunity-specific and per-acre prices can vary significantly based on the prospect. As a result, it is difficult to estimate these 2018 capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2018. +Our 2018 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2018 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2018 and the hedges we currently have in place. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 11 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2017 . See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” +Our cash flows for the years ended December 31, 2017, 2016 and 2015 are presented below. +Year Ended December 31, +2017 +2016 +2015 +(In thousands) +Net cash provided by operating activities +$ +299,125 +$ +134,086 +$ +208,535 +Net cash used in investing activities +(824,003 +) +(405,640 +) +(425,154 +) +Net cash provided by financing activities +408,499 +467,706 +224,944 +Net change in cash +$ +(116,379 +) +$ +196,152 +$ +8,325 +Cash Flows Provided by Operating Activities +Net cash provided by operating activities increased by $165.0 million to $299.1 million for the year ended December 31, 2017 , as compared to net cash provided by operating activities of $134.1 million for the year ended December 31, 2016 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $324.2 million for the year ended December 31, 2017 from $132.3 million for the year ended December 31, 2016 . This increase was primarily attributable to higher oil and natural gas production and higher commodity prices realized during the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . Changes in our operating assets and liabilities between December 31, 2016 and December 31, 2017 also resulted in a net decrease of approximately $26.9 million in net cash provided by operating activities for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . +71 +Table of Contents +Net cash provided by operating activities decreased by $74.4 million to $134.1 million for the year ended December 31, 2016 , as compared to net cash provided by operating activities of $208.5 million for the year ended December 31, 2015 . Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $132.3 million for the year ended December 31, 2016 from $199.6 million for the year ended December 31, 2015 . This decrease was primarily attributable to the decrease in our realized gain on derivatives, which declined $67.8 million to $9.3 million for the year ended December 31, 2016, as compared to $77.1 million for the year ended December 31, 2015. Changes in our operating assets and liabilities between December 31, 2015 and December 31, 2016 also resulted in a net decrease of approximately $7.2 million in net cash provided by operating activities for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 . +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. In addition, we attempt to avoid long-term service agreements where possible in order to minimize ongoing future commitments. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities increased by $418.4 million to $824.0 million for the year ended December 31, 2017 from $405.6 million for the year ended December 31, 2016 . This increase in net cash used in investing activities was primarily attributable to (i) an increase of $320.4 million in oil and natural gas properties capital expenditures for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , (ii) an increase of approximately $46.0 million in expenditures for midstream and other property and equipment, which includes the construction and installation of an expansion of the Black River Processing Plant, additional salt water disposal wells and new pipeline infrastructure and (iii) the release from escrow of $43.1 million of potential like-kind-exchange funds during the year ended December 31, 2016 in connection with the sale of the Loving County Processing System to EnLink in 2015, but no similar release of funds occurring in 2017. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2017 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition of additional leasehold acreage and mineral interests in the Delaware Basin. +Net cash used in investing activities decreased by $19.5 million to $405.6 million for the year ended December 31, 2016 from $425.2 million for the year ended December 31, 2015 . This decrease in net cash used in investing activities included (i) a decrease of $53.6 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2016 , as compared to the year ended December 31, 2015 , (ii) an increase of approximately $10.3 million in expenditures for midstream and other property and equipment, which includes the construction of the Black River Processing Plant and new pipeline infrastructure, (iii) a decrease in cash used for acquisitions, as the merger with Harvey E. Yates Company, a subsidiary of HEYCO Energy Group, Inc., occurred in 2015, (iv) a reduction in proceeds from sales of assets as the sale of the Loving County Processing System to EnLink occurred in 2015 and (v) a decrease in our restricted cash of $43.7 million attributable to the release from escrow of potential like-kind-exchange funds in connection with the sale of the Loving County Processing System to EnLink. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2016 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition of additional acreage and mineral interests in the Delaware Basin. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $408.5 million for the year ended December 31, 2017 , as compared to net cash provided by financing activities of $467.7 million for the year ended December 31, 2016 . The net cash provided by financing activities for the year ended December 31, 2017 was primarily attributable to the total proceeds from our October 2017 equity offering of $208.7 million , contributions related to the formation of San Mateo of $171.5 million and contributions from non-controlling interest owners of less-than-wholly subsidiaries of $44.1 million , offset by distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries of $10.0 million , the payment of $5.8 million in taxes related to net share settlement of stock-based compensation and the purchase of the non-controlling interest in a less-than-wholly-owned subsidiary of $2.7 million . +Net cash provided by financing activities was $467.7 million for the year ended December 31, 2016 , as compared to net cash provided by financing activities of $224.9 million for the year ended December 31, 2015 . The net cash provided by financing activities for the year ended December 31, 2016 was primarily attributable to the total proceeds of the 2016 equity +72 +Table of Contents +offerings of $288.5 million , the total proceeds of the December 2016 notes offering of $184.6 million and borrowings under our Credit Agreement of $120.0 million , offset by the costs of the 2016 equity offerings of $0.8 million , the costs of the December 2016 notes offering of $2.7 million, the repayment of $120.0 million in borrowings under our Credit Agreement in December 2016 and the payment of $1.9 million in taxes related to net share settlement of stock-based compensation. +Net cash provided by financing activities was $224.9 million for the year ended December 31, 2015 , as compared to net cash provided by financing activities of $321.2 million for the year ended December 31, 2014. The net cash provided by financing activities for the year ended December 31, 2015 was primarily attributable to the total proceeds of our April 2015 equity offering of $188.7 million , the total proceeds of our April 2015 notes offering of $400.0 million, borrowings under our Credit Agreement of $125.0 million and capital contributed from the non-controlling interest owners in our less-than-wholly-owned subsidiaries of $0.6 million, offset by the costs of the April 2015 equity offering of $1.2 million, the costs of the April 2015 notes offering of $9.6 million, the repayment of $477.0 million in borrowings under our Credit Agreement during the period and the payment of $1.6 million in taxes related to net share settlement of stock-based compensation. +See Note 6 to the consolidated financial statements in this Annual Report for a summary of our debt, including our Credit Agreement and the senior notes. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2017 , the material off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) non-operated drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) firm transportation, gathering, processing and disposal commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 13 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2017 . +Payments Due by Period +Total +Less Than 1 Year +1-3 Years +3-5 Years +More Than 5 Years +(In thousands) +Contractual Obligations: +Revolving credit borrowings, including letters of credit (1) +$ +2,100 +$ +— +$ +— +$ +2,100 +$ +— +Senior unsecured notes (2) +575,000 +— +— +— +575,000 +Office leases +22,620 +2,495 +5,130 +5,434 +9,561 +Non-operated drilling commitments (3) +24,842 +24,842 +— +— +— +Drilling rig contracts (4) +36,517 +27,499 +9,018 +— +— +Asset retirement obligations +26,256 +1,176 +779 +2,350 +21,951 +Natural gas transportation, gathering and processing agreements with non-affiliates (5) +200,262 +11,922 +30,847 +45,046 +112,447 +Gathering, processing and disposal agreements with San Mateo (6) +232,555 +— +12,253 +69,994 +150,308 +Natural gas plant engineering, procurement, construction and +installation contract (7) +5,580 +5,580 +— +— +— +Total contractual cash obligations +$ +1,125,732 +$ +73,514 +$ +58,027 +$ +124,924 +$ +869,267 +__________________ +(1) +At December 31, 2017 , we had no borrowings outstanding under the Credit Agreement and approximately $2.1 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020. +(2) +The amounts included in the table above represent principal maturities only. Interest expense on our 6.875% senior notes due 2023 that are outstanding as of December 31, 2017 is expected to be approximately $39.5 million each year until maturity. +(3) +At December 31, 2017 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2017 . If all of these wells are drilled and +73 +Table of Contents +completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $24.8 million at December 31, 2017 , which we expect to incur within the next year. +(4) +We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) +Effective October 1, 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. In addition, effective October 25, 2017, we entered into an 18-year fixed-fee natural gas transportation agreement where we committed to deliver a portion of the residue natural gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline in Eddy County, New Mexico. In late 2017, we also entered into a fixed-fee NGL transportation and fractionation agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing Plant. We are committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed late in 2019. We have no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then we do not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then we will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If we do not meet our NGL volume commitment in any quarter during the seven-year commitment period, we will be required to pay a deficiency fee per gallon of NGL deficiency. The amounts in the table assume that the seven-year period containing minimum NGL volume commitments begins in late 2019. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(6) +Effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(7) +Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Historically, the markets for oil, natural gas and NGLs have been volatile and these markets will likely continue to be volatile in the future. Prices for oil, natural gas and NGLs affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or NGLs that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +In 2017 , oil and natural gas prices remained significantly below their most recent highs in 2014, although oil prices, in particular, did begin to improve in the latter half of 2017. Oil prices had increased to $60.42 per Bbl in late December 2017 from $53.72 on December 31, 2016 . Natural gas prices had increased to $3.42 per MMBtu in mid-May 2017 from $2.34 per MMBtu on December 31, 2016 , but had declined to $2.60 per MMBtu in late December 2017. The sharp declines in oil and natural gas prices since late 2014 impacted our revenues, profitability and cash flows in 2015 and 2016, as compared to 2014, but the improvement in commodity prices, as well as our increased oil and natural gas production, resulted in significant improvements in our revenues, profitability and cash flows during 2017 . Future declines in oil and natural gas prices could have an adverse impact on our borrowing capacity, ability to obtain additional capital, revenues, profitability and cash flows. We are uncertain if oil and natural gas prices may continue to rise from their current levels, and in fact, oil and natural gas prices may decrease again in future periods. +For the year ended December 31, 2017 , oil prices averaged $50.80 per Bbl, ranging from a high of $60.42 per Bbl in late December to a low of $42.53 per Bbl in late June , based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $49.28 per Bbl ( $48.81 per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2017 , as compared to $41.19 per Bbl ( $42.34 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2016 . At February 21, 2018 , the +74 +Table of Contents +NYMEX West Texas Intermediate oil futures contract for the earliest delivery date had improved somewhat, closing at $61.68 per Bbl, as compared to $54.06 per Bbl at February 21, 2017 . +For the year ended December 31, 2017 , natural gas prices averaged $3.02 per MMBtu, ranging from a high of approximately $3.42 per MMBtu in mid-May to a low of approximately $2.56 per MMBtu in late February , based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $3.72 per Mcf ( $3.70 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2017 , as compared to $2.66 per Mcf ( $2.78 per Mcf including realized gains from natural gas and NGL derivatives) for the year ended December 31, 2016 . At February 21, 2018 , the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had remained relatively unchanged from late December 2017, closing at $2.66 per MMBtu, as compared to $2.56 per MMBtu at February 21, 2017 . +Coinciding with the improvements in oil and natural gas prices during 2017, we have experienced price increases from our service providers for some of the products and services we use in our drilling, completion and production operations. If oil and natural gas prices remain at their current levels for a longer period of time or should they increase further, we would anticipate receiving additional price increases for drilling, completion and production products and services, although we can provide no assurances as to the eventual magnitude of these increases. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2017 . Such information is incorporated herein by reference. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties +75 +Table of Contents +are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10% discount factor is used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related reserves. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. These instruments typically consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized gain (loss) on derivatives.” Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under Revenues as “Realized gain (loss) on derivatives.” +76 +Table of Contents +Revenue Recognition +We follow the sales method of accounting for our oil, natural gas and NGL revenue, whereby we recognize revenue, net of royalties, on all oil, natural gas and NGLs sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural gas and NGLs are produced and sold, and we accrue for revenue earned but not yet received. We recognize midstream services revenues at the time services have been rendered and the price is fixed and determinable. See Note 2 to the consolidated financial statements in this Annual Report for a description of the impact of the adoption of Accounting Standard Update 2014-09, Revenue from Contracts with Customers (Topic 606) on our 2018 consolidated financial statements. +Stock-Based Compensation +We account for stock-based compensation in accordance with Accounting Standards Codification 718. Since 2012, all stock option awards have been granted under the 2012 Long-Term Incentive Plan or, for awards granted after June 10, 2015, under the Amended and Restated 2012 Long-Term Incentive Plan, and all of these awards were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these awards have been accounted for as liability instruments. We used the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, prior to the beginning of 2016, we estimated the future volatility of our stock using the historical volatility of the common stock of a group of companies we consider to be a representative peer group. Beginning in 2016, we began using our own historical volatility to estimate the future volatility of our stock as we had four years of historical stock prices as a publicly traded company. Management believes that, beginning in 2016, our own average historical volatility rates are the best available indicator of future volatility. +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the fair value of our stock on the date of the grant. See Note 8 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2017 . Such information is incorporated herein by reference. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 7 to the consolidated financial statements in this Annual Report for additional information of the impact of the 2017 Tax Cuts and Jobs Act to our consolidated financial statements. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government +77 +Table of Contents +regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” +Recent Accounting Pronouncements +See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2017 , RBC, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and SunTrust Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2017 , we had entered into various costless collar and swap contracts to mitigate our exposure to fluctuations in oil, natural gas and NGL prices, each with an established price floor and ceiling for the costless collars and fixed price for the swaps. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil, natural gas or NGL volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +During the year ended December 31, 2017 , we entered into various swap contracts to mitigate our exposure to price differences between NYMEX West Texas Intermediate Cushing and Argus West Texas Intermediate Midland crude oil and to fluctuations in NGL prices. When the settlement price is below the fixed price established by one or more of these swaps, we receive from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil or NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, +78 +Table of Contents +we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil or NGL volume. +See Note 11 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2017 . Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2017 , we had no outstanding borrowings under our Credit Agreement and $575.0 million in senior notes outstanding at a coupon rate of 6.875% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our oil, natural gas and NGL derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 21, 2018 were RBC, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and SunTrust Bank (or affiliates thereof), which are lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2017, 2016 and 2015 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report. See the index to the financial statements in Item 15. +79 +Table of Contents +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the three months ended September 30, 2017, we completed the implementation of new accounting and land administration software applications. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change, including procedures to preserve the integrity of the data converted during the application implementations. Additionally, we provided training related to these applications to individuals using the applications to carry out their job responsibilities. We believe the new applications will enhance our internal control over financial reporting due to enhanced automation and integration of related processes. As a result, we have modified the design and documentation of internal control processes and procedures relating to the new applications to complement and supplement existing internal control documentation. The implementation of the new applications was not undertaken in response to any deficiencies in our internal control over financial reporting. +During the three months ended December 31, 2017, we completed the implementation of a new reserves software application. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change, including procedures to preserve the integrity of the data converted during the application implementations. Additionally, we provided training related to this application to individuals using the application to carry out their job responsibilities. We believe this new application will enhance our internal control over financial reporting due to enhanced automation and integration of related processes. We have modified the design and documentation of internal control processes and procedures relating to this new application to complement and supplement existing internal control documentation. The implementation of the new reserves software application was not undertaken in response to any deficiencies in our internal control over financial reporting. +During the three months ended December 31, 2017 , we completed the design and documentation of internal control processes and procedures relating to the new accounting, land administration and reserves software applications. Testing of the controls related to the new applications is completed and is included in the scope of our assessment of our internal control over financial reporting for the year ended December 31, 2017 . +There were no other changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2017 as included herein. +80 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +81 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017 and 2016 , the related statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and our report dated February 28, 2018 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 28, 2018 +82 +Table of Contents +Item 9B. Other Information. +Not applicable. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. +83 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2017 and 2016 , Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 . +2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report. +84 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1 filed on August 12, 2011) . +2.2 +Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 20, 2015).* +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to the Annual Report on Form 10-K for the year ended December 31, 2014). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.4 to the Annual Report on Form 10-K for the year ended December 31, 2014). +2.5 +Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.5 to the Annual Report on Form 10-K for the year ended December 31, 2014).* +2.6 +Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on March 2, 2015).* +2.7 +Amendment No. 5 to Agreement and Plan of Merger, dated as of April 15, 2015, by and among HEYCO Energy Group, Inc., Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on April 15, 2015). +2.8 +Amendment No. 6 to Agreement and Plan of Merger, dated as of July 20, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.9 +Amendment No. 7 to Agreement and Plan of Merger, dated as of August 24, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.10 +Amendment No. 8 to Agreement and Plan of Merger, dated as of September 18, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +2.11 +Amendment No. 9 to Agreement and Plan of Merger, dated as of March 1, 2016, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016). +2.12 +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).* +3.1 +Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 filed on August 12, 2011). +3.2 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +85 +Table of Contents +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.5 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 2, 2015). +4.3 +Indenture, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015). +4.4 +First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf Midstream, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 5, 2015). +4.5 +Second Supplemental Indenture, dated as of November 4, 2015, by and among Matador Resources Company, MRC Permian LKE Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). +4.6 +Third Supplemental Indenture, dated as of June 8, 2016, by and among Matador Resources Company, Black River Water Management Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 14, 2016). +4.7 +Fourth Supplemental Indenture, dated as of February 17, 2017, by and among Matador Resources Company, Black River Water Management Company, LLC, DLK Black River Midstream, LLC, Longwood Midstream Holdings, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 24, 2017). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.8† +First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +86 +Table of Contents +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.10† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.11† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.12† +Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.13† +Matador Resources Company Amended and Restated Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 14, 2016). +10.14† +Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.15† +First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.16† +Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.17† +Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.18† +Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.19† +Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.20† +Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.21† +Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.22† +Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.23† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.24† +Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.25† +Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.26† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011). +87 +Table of Contents +10.27† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.28† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.29† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.30† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.31 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.32 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.33 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.34 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.35 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.36 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.37 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.38 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.39 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.40 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.41 +Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016). +88 +Table of Contents +10.42 +Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016). +10.43 +Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017) +10.44† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.45† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.46† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.47† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.48† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.49† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.50 +Purchase Agreement, dated as of April 9, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 14, 2015). +10.51† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.52† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.53 +Purchase Agreement, dated as of December 6, 2016, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 9, 2016). +10.54† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.62 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.55† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.56† +Form of Letter Agreement between Matador Resources Company and certain directors modifying Restricted Stock Unit Award Agreements (incorporated by reference to Exhibit 10.64 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.57† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.58† +Form of Restricted Stock Unit Award Agreement for Annual Grants relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +89 +Table of Contents +10.59† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.60† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.61† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.62† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.63† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.64† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.65† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.66† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +† +Indicates a management contract or compensatory plan or arrangement. +* +Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +90 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +February 28, 2018 +By: +/s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Joseph Wm. Foran +Chairman and Chief Executive Officer +February 28, 2018 +Joseph Wm. Foran +(Principal Executive Officer) +/s/ David E. Lancaster +Executive Vice President and Chief Financial Officer +February 28, 2018 +David E. Lancaster +(Principal Financial Officer) +/s/ Robert T. Macalik +Senior Vice President and Chief Accounting Officer +February 28, 2018 +Robert T. Macalik +(Principal Accounting Officer) +/s/ Reynald A. Baribault +Director +February 28, 2018 +Reynald A. Baribault +/s/ R. Gaines Baty +Director +February 28, 2018 +R. Gaines Baty +/s/ Craig T. Burkert +Director +February 28, 2018 +Craig T. Burkert +/s/ William M. Byerley +Director +February 28, 2018 +William M. Byerley +/s/ Julia P. Forrester +Director +February 28, 2018 +Julia P. Forrester +/s/ Steven W. Ohnimus +Director +February 28, 2018 +Steven W. Ohnimus +/s/ Timothy E. Parker +Director +February 28, 2018 +Timothy E. Parker +/s/ David M. Posner +Director +February 28, 2018 +David M. Posner +/s/ Kenneth L. Stewart +Director +February 28, 2018 +Kenneth L. Stewart +/s/ George M. Yates +Director +February 28, 2018 +George M. Yates +91 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or salt water. +Bcf . One billion cubic feet of natural gas. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +92 +Table of Contents +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or salt water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +93 +Table of Contents +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +94 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2017, 2016 and 2015 +Contents +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2017 and 2016 +F-3 +Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015 +F-4 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015 +F-5 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 +F-6 +Notes to Consolidated Financial Statements +F-7 +Unaudited Supplementary Information +F-38 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (collectively the “Company”) as of December 31, 2017 and 2016 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2017 , and the related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017 , in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +February 28, 2018 +F-2 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2017 +2016 +ASSETS +Current assets +Cash +$ +96,505 +$ +212,884 +Restricted cash +5,977 +1,258 +Accounts receivable +Oil and natural gas revenues +65,962 +34,154 +Joint interest billings +67,225 +19,347 +Other +8,031 +5,167 +Derivative instruments +1,190 +— +Lease and well equipment inventory +5,993 +3,045 +Prepaid expenses and other assets +6,287 +3,327 +Total current assets +257,170 +279,182 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +3,004,770 +2,408,305 +Unproved and unevaluated +637,396 +479,736 +Midstream and other property and equipment +281,096 +160,795 +Less accumulated depletion, depreciation and amortization +(2,041,806 +) +(1,864,311 +) +Net property and equipment +1,881,456 +1,184,525 +Other assets +7,064 +958 +Total assets +$ +2,145,690 +$ +1,464,665 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +11,757 +$ +4,674 +Accrued liabilities +174,348 +101,460 +Royalties payable +61,358 +23,988 +Amounts due to affiliates +10,302 +8,651 +Derivative instruments +16,429 +24,203 +Advances from joint interest owners +2,789 +1,700 +Amounts due to joint ventures +4,873 +4,251 +Other current liabilities +750 +578 +Total current liabilities +282,606 +169,505 +Long-term liabilities +Senior unsecured notes payable +574,073 +573,924 +Asset retirement obligations +25,080 +19,725 +Derivative instruments +— +751 +Amounts due to joint ventures +— +1,771 +Other long-term liabilities +6,385 +7,544 +Total long-term liabilities +605,538 +603,715 +Commitments and contingencies (Note 13) +Shareholders’ equity +Common stock — $0.01 par value, 160,000,000 and 120,000,000 shares authorized; 108,513,597 and 99,518,764 shares issued; and 108,510,160 and 99,511,931 shares outstanding, respectively +1,085 +995 +Additional paid-in capital +1,666,024 +1,325,481 +Accumulated deficit +(510,484 +) +(636,351 +) +Treasury stock, at cost, 3,437 and 6,833 shares, respectively +(69 +) +— +Total Matador Resources Company shareholders’ equity +1,156,556 +690,125 +Non-controlling interest in subsidiaries +100,990 +1,320 +Total shareholders’ equity +1,257,546 +691,445 +Total liabilities and shareholders’ equity +$ +2,145,690 +$ +1,464,665 +The accompanying notes are an integral part of these financial statements. +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2017 +2016 +2015 +Revenues +Oil and natural gas revenues +$ +528,684 +$ +291,156 +$ +278,340 +Third-party midstream services revenues +10,198 +5,218 +1,864 +Realized (loss) gain on derivatives +(4,321 +) +9,286 +77,094 +Unrealized gain (loss) on derivatives +9,715 +(41,238 +) +(39,265 +) +Total revenues +544,276 +264,422 +318,033 +Expenses +Production taxes, transportation and processing +58,275 +43,046 +35,650 +Lease operating +67,313 +56,202 +54,704 +Plant and other midstream services operating +13,039 +5,389 +3,489 +Depletion, depreciation and amortization +177,502 +122,048 +178,847 +Accretion of asset retirement obligations +1,290 +1,182 +734 +Full-cost ceiling impairment +— +158,633 +801,166 +General and administrative +66,016 +55,089 +50,105 +Total expenses +383,435 +441,589 +1,124,695 +Operating income (loss) +160,841 +(177,167 +) +(806,662 +) +Other income (expense) +Net gain on asset sales and inventory impairment +23 +107,277 +908 +Interest expense +(34,565 +) +(28,199 +) +(21,754 +) +Other income (expense) +3,551 +(4 +) +616 +Total other (expense) income +(30,991 +) +79,074 +(20,230 +) +Income (loss) before income taxes +129,850 +(98,093 +) +(826,892 +) +Income tax (benefit) provision +Current +(8,157 +) +(1,036 +) +2,959 +Deferred +— +— +(150,327 +) +Total income tax benefit +(8,157 +) +(1,036 +) +(147,368 +) +Net income (loss) +138,007 +(97,057 +) +(679,524 +) +Net income attributable to non-controlling interest in subsidiaries +(12,140 +) +(364 +) +(261 +) +Net income (loss) attributable to Matador Resources Company shareholders +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +Earnings (loss) per common share +Basic +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +Diluted +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +Weighted average common shares outstanding +Basic +102,029 +91,273 +81,537 +Diluted +102,543 +91,273 +81,537 +The accompanying notes are an integral part of these financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2017, 2016 and 2015 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital +Retained earnings (accumulated deficit) +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders ’ equity +Common Stock +Preferred Stock +Shares +Amount +Shares +Amount +Shares +Amount +Balance at January 1, 2015 +73,374 +$ +734 +— +$ +— +$ +724,819 +$ +140,855 +31 +$ +— +$ +866,408 +$ +133 +$ +866,541 +Issuance of common stock +10,329 +104 +— +— +260,148 +— +— +— +260,252 +— +260,252 +Issuance of preferred stock +— +— +150 +1 +32,489 +— +— +— +32,490 +— +32,490 +Cost to issue equity +— +— +— +— +(1,151 +) +— +— +— +(1,151 +) +— +(1,151 +) +Conversion of preferred stock to common stock +1,500 +15 +(150 +) +(1 +) +(14 +) +— +— +— +— +— +— +Stock-based compensation expense related to equity-based awards +— +— +— +— +9,333 +— +— +— +9,333 +— +9,333 +Stock options exercised, net of options forfeited in net share settlements +25 +— +— +— +10 +— +— +— +10 +— +10 +Liability-based stock option awards settled +25 +— +— +— +446 +— +— +— +446 +— +446 +Restricted stock issued +429 +4 +— +— +(4 +) +— +— +— +— +— +— +Restricted stock forfeited +— +— +— +— +— +— +138 +— +— +— +— +Vesting of restricted stock units +52 +1 +— +— +(1 +) +— +— +— +— +— +— +Cancellation of treasury stock +(167 +) +(2 +) +— +— +2 +— +(167 +) +— +— +— +— +Capital contributed from less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +562 +562 +Current period net (loss) income +— +— +— +— +— +(679,785 +) +— +— +(679,785 +) +261 +(679,524 +) +Balance at December 31, 2015 +85,567 +856 +— +— +1,026,077 +(538,930 +) +2 +— +488,003 +956 +488,959 +Issuance of common stock pursuant to public offerings +13,500 +135 +— +— +288,375 +— +— +— +288,510 +— +288,510 +Issuance of common stock pursuant to employee stock compensation plan +471 +4 +— +— +(4 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +51 +1 +— +— +(1 +) +— +— +— +— +— +— +Cost to issue equity +— +— +— +— +(1,190 +) +— +— +— +(1,190 +) +— +(1,190 +) +Stock-based compensation expense related to equity-based awards +— +— +— +— +11,958 +— +— +— +11,958 +— +11,958 +Stock options exercised, net of options forfeited in net share settlements +36 +— +— +— +10 +— +— +— +10 +— +10 +Liability-based stock option awards settled +10 +— +— +— +255 +— +— +— +255 +— +255 +Restricted stock forfeited +— +— +— +— +— +— +120 +— +— +— +— +Cancellation of treasury stock +(116 +) +(1 +) +— +— +1 +— +(116 +) +— +— +— +— +Current period net (loss) income +— +— +— +— +— +(97,421 +) +— +— +(97,421 +) +364 +(97,057 +) +Balance at December 31, 2016 +99,519 +995 +— +— +1,325,481 +(636,351 +) +6 +— +690,125 +1,320 +691,445 +Issuance of common stock pursuant to public offerings +8,000 +80 +— +— +208,640 +— +— +— +208,720 +— +208,720 +Issuance of common stock pursuant to employee stock compensation plan +530 +5 +— +— +(5 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors' and advisors' compensation plan +77 +1 +— +— +(1 +) +— +— +— +— +— +— +Cost to issue equity +— +— +— +— +(280 +) +— +— +— +(280 +) +— +(280 +) +Stock-based compensation expense related to equity-based awards including amounts capitalized +— +— +— +— +19,594 +— +— +— +19,594 +— +19,594 +Stock options exercised, net of options forfeited in net share settlements +514 +5 +— +— +(1,189 +) +— +— +— +(1,184 +) +— +(1,184 +) +Restricted stock forfeited +— +— +— +— +— +— +123 +(1,658 +) +(1,658 +) +— +(1,658 +) +Purchase of non-controlling interest of less-than-wholly-owned subsidiary +— +— +— +— +(1,250 +) +— +— +— +(1,250 +) +(1,403 +) +(2,653 +) +Contributions related to formation of Joint Venture (see Note 5) +— +— +— +— +116,622 +— +— +— +116,622 +54,878 +171,500 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +44,100 +44,100 +Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries +— +— +— +— +— +— +— +— +— +(10,045 +) +(10,045 +) +Cancellation of treasury stock +(126 +) +(1 +) +— +— +(1,588 +) +— +(126 +) +1,589 +— +— +— +Current period net income +— +— +— +— +— +125,867 +1 +— +— +125,867 +12,140 +138,007 +Balance at December 31, 2017 +108,514 +$ +1,085 +— +$ +— +$ +1,666,024 +$ +(510,484 +) +3 +$ +(69 +) +$ +1,156,556 +$ +100,990 +$ +1,257,546 +The accompanying notes are an integral part of these financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +2017 +2016 +2015 +Operating activities +Net income (loss) +$ +138,007 +$ +(97,057 +) +$ +(679,524 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized (gain) loss on derivatives +(9,715 +) +41,238 +39,265 +Depletion, depreciation and amortization +177,502 +122,048 +178,847 +Accretion of asset retirement obligations +1,290 +1,182 +734 +Full-cost ceiling impairment +— +158,633 +801,166 +Stock-based compensation expense +16,654 +12,362 +9,450 +Deferred income tax benefit +— +— +(150,327 +) +Amortization of debt issuance cost +468 +1,148 +852 +Net gain on asset sales and inventory impairment +(23 +) +(107,277 +) +(908 +) +Changes in operating assets and liabilities +Accounts receivable +(82,549 +) +(14,259 +) +3,633 +Lease and well equipment inventory +(3,623 +) +(700 +) +(180 +) +Prepaid expenses and other assets +(2,960 +) +(124 +) +(544 +) +Other assets +(6,425 +) +490 +(552 +) +Accounts payable, accrued liabilities and other current liabilities +33,559 +6,611 +1,375 +Royalties payable +37,370 +7,495 +1,654 +Advances from joint interest owners +1,089 +1,000 +700 +Income taxes payable +— +(2,848 +) +2,405 +Other long-term liabilities +(1,519 +) +4,144 +489 +Net cash provided by operating activities +299,125 +134,086 +208,535 +Investing activities +Oil and natural gas properties capital expenditures +(699,445 +) +(379,067 +) +(432,715 +) +Expenditures for midstream and other property and equipment +(120,816 +) +(74,845 +) +(64,499 +) +Proceeds from sale of assets +977 +5,173 +139,836 +Business combination, net of cash acquired +— +— +(24,028 +) +Restricted cash +— +43,098 +(43,098 +) +Restricted cash in less-than-wholly-owned subsidiaries +(4,719 +) +1 +(650 +) +Net cash used in investing activities +(824,003 +) +(405,640 +) +(425,154 +) +Financing activities +Repayments of borrowings +— +(120,000 +) +(476,982 +) +Borrowings under Credit Agreement +— +120,000 +125,000 +Proceeds from issuance of common stock +208,720 +288,510 +188,720 +Proceeds from issuance of senior unsecured notes +— +184,625 +400,000 +Cost to issue equity +(280 +) +(847 +) +(1,158 +) +Cost to issue senior unsecured notes +— +(2,734 +) +(9,598 +) +Proceeds from stock options exercised +2,920 +100 +10 +Capital commitments from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +562 +Contributions related to formation of Joint Venture +171,500 +— +— +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +44,100 +— +— +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries +(10,045 +) +— +— +Taxes paid related to net share settlement of stock-based compensation +(5,763 +) +(1,948 +) +(1,610 +) +Purchase of non-controlling interest of less-than-wholly-owned subsidiary +(2,653 +) +— +— +Net cash provided by financing activities +408,499 +467,706 +224,944 +(Decrease) increase in cash +(116,379 +) +196,152 +8,325 +Cash at beginning of year +212,884 +16,732 +8,407 +Cash at end of year +$ +96,505 +$ +212,884 +$ +16,732 +Supplemental disclosures of cash flow information (Note 14) +The accompanying notes are an integral part of these financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2017, 2016 and 2015 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $23.1 million , $15.7 million and $6.9 million of its general and administrative costs in 2017 , 2016 and 2015 , respectively. The Company capitalized $7.3 million , $3.7 million and $3.9 million of its interest expense for the years ended December 31, 2017, 2016 and 2015 , respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the year ended December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2017. +During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million , exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). +During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million , exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream and Other Property and Equipment +Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments. +Revenue Recognition +The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable. See below for a discussion of the impact of the adoption of Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) on the Company’s 2018 consolidated financial statements. +For the year ended December 31, 2017 , four significant purchasers accounted for 60% of the Company’s total oil, natural gas and natural gas liquids revenues: Occidental Energy Marketing, Inc. ( 23% ), Plains Marketing, L.P. ( 14% ), Shell Trading (US) Company ( 12% ) and Western Refining Crude Oil ( 11% ). For the year ended December 31, 2016 , three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. ( 18% ), Shell Trading (US) Company ( 17% ) and Occidental Energy Marketing, Inc. ( 13% ). For the year ended December 31, 2015 , three significant purchasers accounted for approximately 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company ( 33% ), Enterprise Crude Oil LLC ( 14% ) and Sequent Energy Management, L.P. ( 12% ). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2017, 2016 and 2015 , approximately 43% , 38% and 39% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Stock-Based Compensation +The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units. +The Company’s consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015 include a stock-based compensation (non-cash) expense of $16.7 million , $12.4 million and $9.5 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $3.0 million (including a one-time expense of $1.5 million resulting from a change in the vesting schedule applicable to equity awards granted to independent members of the Company’s Board of Directors), $1.0 million and $0.9 million in 2017 , 2016 and 2015 , respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2017, 2016 and 2015 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2017, 2016 and 2015 . +On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changes U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The Tax Cuts and Jobs Act permanently reduces the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018. For the year ended December 31, 2017 , the Company re-valued its deferred tax assets and liabilities at the enacted rate (see Note 7). +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings (Loss) Per Common Share +The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share data). +Year Ended December 31, +2017 +2016 +2015 +Net income (loss) attributable to Matador Resources Company shareholders — numerator +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +Weighted average common shares outstanding — denominator +Basic +102,029 +91,273 +81,537 +Dilutive effect of options and restricted stock units +514 +— +— +Diluted weighted average common shares outstanding +102,543 +91,273 +81,537 +Earnings (loss) per common share attributable to +Matador Resources Company shareholders +Basic +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +Diluted +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +A total of 1.0 million options to purchase shares of the Company’s common stock were excluded from the calculations above for the year ended December 31, 2017 because their effects were anti-dilutive. +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company. +A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2017 were with Royal Bank of Canada (“RBC”), The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Revenue from Contracts with Customers . In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company adopted the new guidance effective January 1, 2018 using the modified approach. The Company identified all revenue streams and reviewed all contracts and procedures currently in place. The Company determined there is no material impact on its consolidated financial statements as a result of adoption, including no material impact to the timing or amount of revenue recognized, although the Company will be required to include certain additional disclosures regarding revenue from contracts with customers as a result of adoption of ASU 2014-09. +Leases . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company should evaluate new or modified land easements under this ASU beginning at the date of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases, as defined under the new lease standard, determining which practical expedients the Company will use and quantifying the impact of the new lease standard on existing leases. The Company expects to adopt this lease standard on January 1, 2019. +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Statement of Cash Flows . In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) , which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 and believes that the adoption of this ASU will change the presentation of its beginning and ending cash balances and eliminate the presentation of changes in restricted cash balances from investing activities in its consolidated statement of cash flows. +Clarifying the Definition of a Business . In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) , which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017. Entities are required to apply guidance prospectively upon adoption. Effective January 1, 2018, the Company adopted ASU 2017-01, which did not have a material impact on its consolidated financial statements. +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2017 and 2016 (in thousands). +December 31, +2017 +2016 +Oil and natural gas properties +Evaluated (subject to amortization) +$ +3,004,770 +$ +2,408,305 +Unproved and unevaluated (not subject to amortization) +637,396 +479,736 +Total oil and natural gas properties +3,642,166 +2,888,041 +Accumulated depletion +(2,021,169 +) +(1,850,882 +) +Net oil and natural gas properties +1,620,997 +1,037,159 +Midstream and other property and equipment +Midstream equipment and facilities +258,725 +145,662 +Furniture, fixtures and other equipment +6,109 +5,487 +Software +7,942 +3,206 +Land +2,892 +1,437 +Leasehold improvements +5,428 +5,003 +Total midstream and other property and equipment +281,096 +160,795 +Accumulated depreciation +(20,637 +) +(13,429 +) +Net midstream and other property and equipment +260,459 +147,366 +Net property and equipment +$ +1,881,456 +$ +1,184,525 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2017 and the year in which these costs were incurred (in thousands). +Description +2017 +2016 +2015 +2014 and prior +Total +Costs incurred for +Property acquisition +$ +213,076 +$ +125,689 +$ +222,912 +$ +45,809 +$ +607,486 +Exploration wells +16,688 +988 +547 +— +18,223 +Development wells +11,396 +272 +19 +— +11,687 +Total +$ +241,160 +$ +126,949 +$ +223,478 +$ +45,809 +$ +637,396 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2017 are related almost entirely to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past five years. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $29.9 million at December 31, 2017 . Of this total, $18.2 million was associated with exploration wells and $11.7 million was associated with development wells. The Company anticipates that most of the $29.9 million associated with these wells in progress at December 31, 2017 will be transferred to the amortization base during 2018 . +NOTE 4 — ASSET RETIREMENT OBLIGATIONS +In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands). +Year Ended December 31, +2017 +2016 +Beginning asset retirement obligations +$ +20,640 +$ +15,420 +Liabilities incurred during period +2,920 +1,791 +Liabilities settled during period +(430 +) +(375 +) +Revisions in estimated cash flows +1,836 +2,622 +Accretion expense +1,290 +1,182 +Ending asset retirement obligations +26,256 +20,640 +Less: current asset retirement obligations (1) +(1,176 +) +(915 +) +Long-term asset retirement obligations +$ +25,080 +$ +19,725 +__________________ +(1) +Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2017 and 2016 . +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES +Joint Venture +On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo, a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo’s other assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of San Mateo. +The Company and Five Point own 51% and 49% of San Mateo, respectively. Five Point provided initial cash consideration of $176.4 million to San Mateo in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by San Mateo to the Company as a special distribution. Through January 31, 2018, the Company had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018 and may earn an additional $58.8 million in performance incentives over the next four years . The Company contributed the Delaware Midstream Assets and $5.1 million in cash to San Mateo in exchange for its 51% interest. San Mateo is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo being accounted for as a non-controlling interest. +The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas to San Mateo pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15 -year, fixed fee natural gas processing agreement (see Note 13). +Business Combinations +On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross ( 18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction. +As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). +Divestitures +On October 1, 2015 , the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant. +Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million , and the Company received net proceeds of approximately $139.8 million after deducting customary purchase price adjustments of approximately $3.6 million . In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement. +Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15 -year term of the gathering and processing agreement. +During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink began processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +agreement the Company entered into with EnLink was no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016. +The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017, these assets were contributed to San Mateo. +NOTE 6 — DEBT +Credit Agreement +On September 28, 2012 , the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million . MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. Early in the fourth quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2017, and as a result, on October 25, 2017, the borrowing base was increased to $525.0 million and the maximum facility amount remained at $500.0 million . This October 2017 redetermination constituted the regularly scheduled November 1 redetermination. The Company elected to keep the borrowing commitment at $400.0 million . Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 16, 2020. +In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. Total deferred loan costs were $1.0 million at December 31, 2017 , and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +At December 31, 2017 and February 21, 2018 , the Company had no borrowings outstanding under the Credit Agreement and approximately $2.1 million in outstanding letters of credit issued pursuant to the Credit Agreement. +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 6 — DEBT — Continued +A commitment fee of 0.375% to 0.50% , depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of the Company’s assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; +• +engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and +• +take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving the Company or its subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2017 . +Senior Unsecured Notes +On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes were issued at par value, and the net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. +On October 21, 2015, and pursuant to a registered exchange offer, Matador exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Registered Notes. +On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5% . The Company received net proceeds from the Notes Offering of approximately $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. +On May 24, 2017, pursuant to a registered exchange offer, Matador exchanged all of the privately placed Additional Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Additional Registered Notes,” and, collectively with the Registered Notes, the “Notes”). The terms of the Additional +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 6 — DEBT — Continued +Registered Notes are substantially the same as the terms of the Additional Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Additional Notes do not apply to the Additional Registered Notes. +The Notes are Matador’s senior unsecured obligations and are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year. +On or after April 15, 2018 , Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of the years indicated. +Year +Redemption Price +2018 +105.156% +2019 +103.438% +2020 +101.719% +2021 and thereafter +100.000% +At any time prior to April 15, 2018 , Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. +In addition, at any time prior to April 15, 2018 , Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date. +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company; +• +consolidate, merge or transfer all or substantially all of its assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• +default for 30 days in the payment when due of interest on the Notes; +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 6 — DEBT — Continued +• +default in the payment when due of the principal of, or premium, if any, on the Notes; +• +failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets; +• +failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture; +• +failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture; +• +payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more; +• +failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; +• +any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and +• +certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +On February 17, 2017, in connection with the formation of San Mateo (see Note 5), Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the indenture governing the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Guarantor Subsidiaries.” San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes, although they remain restricted subsidiaries under the Indenture. +NOTE 7 —INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2017 and 2016 is as follows (in thousands). +December 31, +2017 +2016 +Deferred tax assets +Unrealized loss on derivatives +$ +3,200 +$ +8,734 +Net operating loss carryforwards +118,134 +137,757 +Alternative minimum tax carryforward +— +8,633 +Percentage depletion carryover +1,582 +2,595 +Property and equipment +— +44,391 +Basis increase related to the San Mateo transaction +18,382 +— +Total deferred tax assets +141,298 +202,110 +Valuation allowance on deferred tax assets +(89,482 +) +(190,255 +) +Total deferred tax assets, net of valuation allowance +51,816 +11,855 +Deferred tax liabilities +Property and equipment +(40,568 +) +— +Other +(11,248 +) +(11,855 +) +Total deferred tax liabilities +(51,816 +) +(11,855 +) +Net deferred tax liabilities +$ +— +$ +— +At December 31, 2017 , the Company had net operating loss carryforwards of $498.4 million for federal income tax purposes and $17.0 million for state income tax purposes available to offset future taxable income, as limited by the applicable +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 7 — INCOME TAXES — Continued +provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024 ; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . +As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company recorded impairment charges of $158.6 million and $801.2 million , respectively, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2017 and 2016 , the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded in 2016 and 2015. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at December 31, 2017 and 2016 due to uncertainties regarding the future utilization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized. +The current income tax (benefit) provision for the years ended December 31, 2017, 2016 and 2015 was comprised of the following (in thousands). +Year Ended December 31, +2017 +2016 +2015 +Current income tax provision +State income tax +$ +21 +$ +108 +$ +371 +Federal alternative minimum tax +(8,178 +) +(1,144 +) +2,588 +Net current income tax (benefit) provision +$ +(8,157 +) +$ +(1,036 +) +$ +2,959 +Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows (in thousands). +Year Ended December 31, +2017 +2016 +2015 +Federal tax expense (benefit) at statutory rate (1) +$ +45,447 +$ +(34,333 +) +$ +(289,412 +) +State income tax +368 +539 +(13,215 +) +Permanent differences (2) +(4,740 +) +(499 +) +698 +Federal alternative minimum tax +— +1,144 +(2,588 +) +AMT credit refundable (net of sequestration) +8,178 +— +— +Tax Cuts and Jobs Act rate change +51,525 +— +— +Change in federal valuation allowance +(101,917 +) +33,688 +145,777 +Change in state valuation allowance +1,139 +(539 +) +8,413 +Net deferred income tax benefit +— +— +(150,327 +) +Net current income tax (benefit) provision +(8,157 +) +(1,036 +) +2,959 +Total income tax benefit +$ +(8,157 +) +$ +(1,036 +) +$ +(147,368 +) +__________________ +(1) +The statutory federal tax rate was 35% for the years ended December 31, 2017, 2016 and 2015 . +(2) +Amount is primarily attributable to stock-based compensation. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the State of New Mexico and the State of Louisiana tax returns is 2015 . The earliest tax years open for examination for the federal and the State of Texas tax returns are 2013 and 2014, respectively. +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 7 — INCOME TAXES — Continued +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2017 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act, the Company revalued its deferred tax assets and liabilities at December 31, 2017, which resulted in a $51.5 million tax provision. As the Company maintained a valuation allowance against its federal and state deferred tax assets at December 31, 2017, a corresponding reduction in the valuation allowance was recorded against this tax provision; therefore, there was no net impact to the Company’s consolidated statement of operations for the year ended December 31, 2017 as a result of this corporate income tax rate change. +Corporate alternative minimum taxes were also repealed under the Tax Cuts and Jobs Act; therefore, corporate alternative minimum tax carryforwards will be refunded. As a result, the Company recorded $8.2 million as a current income tax benefit in its consolidated statement of operations for the year ended December 31, 2017. +On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Cuts and Jobs Act. The Company has recognized the tax impacts related to the revaluation of deferred tax assets and liabilities and the repeal of the corporate alternative minimum tax and included these amounts in its consolidated financial statements for the year ended December 31, 2017. The ultimate tax impacts may differ from these provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions the Company has made, additional regulatory guidance that may be issued, and actions the Company may take as a result of the Tax Cuts and Jobs Act. +NOTE 8 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. +In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2017 , the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. +The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period. +Stock Options +Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or ten years. +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +The fair value of the 75,000 , 77,500 and 87,500 stock option awards outstanding under the 2003 Plan at December 31, 2017, 2016 and 2015 , respectively, was estimated using the following weighted average assumptions. +2017 +2016 +2015 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +2.14 years +3.14 years +0.39 years +Risk-free interest rate +1.98% +1.70% +0.64% +Volatility +43.60% +47.07% +91.98% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +—% +—% +—% +The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2017, 2016 and 2015 . +2017 +2016 +2015 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +4.00 years +3.96 years +4.00 years +Risk-free interest rate +1.77% +1.08% +1.15% +Volatility +47.00% +45.68% +56.89% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +3.66% +1.16% +3.21% +Weighted average fair value of stock option awards granted during the year +$10.49 +$5.65 +$9.90 +The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2017 under the 2003 Plan and the 2012 Incentive Plan is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2016 +2,887 +$ +15.59 +Options granted +1,034 +$ +27.09 +Options exercised +(833 +) +$ +9.20 +Options forfeited +(24 +) +$ +23.81 +Options expired +— +$ +— +Options outstanding at December 31, 2017 +3,064 +$ +21.14 +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +Options outstanding at +December 31, 2017 +Options exercisable at +December 31, 2017 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life +Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$8.18 - $9.55 +294 +0.69 +$ +8.46 +294 +$ +8.46 +$13.22 - $17.80 +625 +3.10 +$ +15.01 +11 +$ +16.45 +$19.71 - $22.70 +839 +2.05 +$ +21.87 +73 +$ +21.50 +$23.40 - $27.33 +1,306 +4.33 +$ +26.47 +141 +$ +24.21 +At December 31, 2017 , the aggregate intrinsic value was $30.6 million for outstanding options and $8.5 million for exercisable options, based on the Company’s quoted closing market price of $31.13 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2017 was 1.07 years. +The total intrinsic value of options exercised during the years ended December 31, 2017, 2016 and 2015 was $13.2 million , $1.6 million and $1.3 million , respectively. The tax related benefit realized from the exercise of stock options totaled $5.0 million , $0.5 million and $0.3 million for the years ended December 31, 2017, 2016 and 2015 , respectively. +At December 31, 2017 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $9.8 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 0.78 years. +The fair value of options vested during 2017 , 2016 and 2015 was $2.1 million , $3.0 million and $1.3 million , respectively. +Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Restricted stock and restricted stock units granted in 2017, 2016 and 2015 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2017 were granted under the 2012 Incentive Plan. +A summary of the non-vested restricted stock and restricted stock units as of December 31, 2017 is presented below (in thousands, except fair value). +Restricted Stock +Restricted Stock Units +Non-vested restricted stock and +restricted stock units +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value +Non-vested at December 31, 2016 +1,039 +$ +18.23 +82 +$ +21.32 +Granted +531 +$ +26.25 +113 +$ +23.77 +Vested +(429 +) +$ +16.54 +(124 +) +$ +22.38 +Forfeited +(37 +) +$ +22.94 +(6 +) +23.45 +Non-vested at December 31, 2017 +1,104 +$ +22.59 +65 +$ +23.36 +At December 31, 2017 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $36.4 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $31.13 per share on that date. +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +At December 31, 2017 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $14.4 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 0.95 years. +The fair value of restricted stock and restricted stock units vested during 2017 , 2016 and 2015 was $9.9 million , $4.6 million and $0.8 million , respectively. +The total tax benefit recognized for all stock-based compensation was $6.8 million , $4.3 million and $3.4 million for the years ended December 31, 2017, 2016 and 2015 , respectively. +During the years ended December 31, 2017, 2016 and 2015 , the total expense attributable to stock options was $7.1 million , $5.9 million and $4.7 million , respectively. At December 31, 2017, 2016 and 2015 , the Company had recorded $0.4 million , $1.4 million and zero of long-term liabilities and zero , zero and $1.0 million of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2017, 2016 and 2015 , respectively. +During the years ended December 31, 2017, 2016 and 2015 , the total expense attributable to restricted stock and restricted stock units was $12.9 million , $6.6 million and $4.7 million , respectively. During the year ended December 31, 2017 , the Company capitalized $3.3 million related to stock-based compensation and expensed the remaining $16.7 million . +In mid-February 2018, the Company granted awards of 667,488 shares of restricted stock and options to purchase 563,408 shares of the Company’s common stock at an exercise price of $29.68 per share to certain of its employees. The fair value of these awards was approximately $26.9 million . All of these awards vest ratably over three years. +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 9 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $0.9 million , $0.7 million and $0.6 million in 2017 , 2016 and 2015 , respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $1.1 million , $0.9 million and $0.8 million in 2017 , 2016 and 2015 , respectively. The Company made no additional contributions in any reporting period presented. +NOTE 10 — EQUITY +Stock Offerings, Retirement and Issuances +On October 10, 2017 , the Company completed a public offering of 8,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.3 million , the Company received net proceeds of approximately $208.4 million . A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, acreage acquisitions and general corporate purposes, including to fund a portion of the Company’s current and future capital expenditures. +On June 1, 2017, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 120,000,000 to 160,000,000 shares. +On December 9, 2016 , the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million , the Company received net proceeds of approximately $145.8 million . On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million , the Company received net proceeds of approximately $141.5 million . +On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million , the Company received net proceeds of approximately $187.6 million . +As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. +On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2017 to satisfy certain conditions under the merger agreement. +Treasury Stock +On November 1, 2017, October 27, 2016 and October 30, 2015, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2017, 2016 and 2015, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2017 , 2016 and 2015 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids (“NGL”) prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2017 , the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling and fixed price for the swaps. Each contract is set to expire at varying times during 2018. +The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2017 . +Notional Quantity (Bbl or MMBtu) +Weighted Average Price Floor ($/Bbl or +$/MMBtu) +Weighted Average Price Ceiling ($/Bbl or +$/MMBtu) +Fair Value of Asset (Liability) +(thousands) +Commodity +Calculation Period +Oil - WTI (1) +01/01/2018 - 12/31/2018 +2,880,000 +$ +44.27 +$ +60.29 +(8,414 +) +Oil - LLS (2) +01/01/2018 - 12/31/2018 +720,000 +$ +45.00 +$ +63.05 +(2,451 +) +Natural Gas +01/01/2018 - 12/31/2018 +16,800,000 +$ +2.58 +$ +3.67 +1,190 +Total open costless collar contracts +$ +(9,675 +) +_____________________ +(1) +NYMEX West Texas Intermediate crude oil. +(2) +Argus Louisiana Light Sweet crude oil. +The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2017 . +Commodity +Calculation Period +Notional Quantity (Bbl or Gal) +Fixed Price +($/Bbl or $/Gal) +Fair Value of Asset (Liability) +(thousands) +Oil Basis Swaps +01/01/2018 - 12/31/2018 +5,220,000 +$ +(1.02 +) +$ +(5,564 +) +Total open swap contracts +$ +(5,564 +) +Total open derivative financial instruments +$ +(15,239 +) +From time-to-time, we enter into derivative financial instruments with certain counterparties. These derivative financial instruments are subject to master netting arrangements, and all but one counterparty allow for cross-commodity master netting provided the settlements dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 (in thousands). +Derivative Instruments +Gross amounts recognized +Gross amounts netted in the consolidated balance sheets +Net amounts presented in the consolidated balance sheets +December 31, 2017 +Current assets +$ +131,092 +$ +(129,902 +) +$ +1,190 +Current liabilities +(146,331 +) +129,902 +(16,429 +) +Total +$ +(15,239 +) +$ +— +$ +(15,239 +) +December 31, 2016 +Current liabilities +$ +(24,203 +) +$ +— +$ +(24,203 +) +Other liabilities +(751 +) +— +(751 +) +Total +$ +(24,954 +) +$ +— +$ +(24,954 +) +The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. +Year Ended December 31, +Type of Instrument +Location in Statement of Operations +2017 +2016 +2015 +Derivative Instrument +Oil +Revenues: Realized (loss) gain on derivatives +$ +(3,657 +) +$ +5,851 +$ +62,259 +Natural Gas +Revenues: Realized (loss) gain on derivatives +(608 +) +3,435 +12,653 +Natural Gas Liquids (NGL) +Revenues: Realized (loss) gain on derivatives +(56 +) +— +2,182 +Realized (loss) gain on derivatives +(4,321 +) +9,286 +77,094 +Oil +Revenues: Unrealized gain (loss) on derivatives +2,638 +(18,969 +) +(31,897 +) +Natural Gas +Revenues: Unrealized gain (loss) on derivatives +7,077 +(22,269 +) +(5,440 +) +Natural Gas Liquids (NGL) +Revenues: Unrealized loss on derivatives +— +— +(1,928 +) +Unrealized gain (loss) on derivatives +9,715 +(41,238 +) +(39,265 +) +Total +$ +5,394 +$ +(31,952 +) +$ +37,829 +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 12 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 +Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 +Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 +Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +At December 31, 2017 and 2016 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximate their fair values due to their short-term maturities. +At December 31, 2017 and 2016 , the fair value of the Company’s Notes was $614.1 million and $605.2 million , respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2017 and 2016 (in thousands). +Fair Value Measurements at +December 31, 2017 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Natural gas derivatives +$ +— +$ +1,190 +$ +— +$ +1,190 +Oil derivatives and basis swaps +— +(16,429 +) +— +(16,429 +) +Total +$ +— +$ +(15,239 +) +$ +— +$ +(15,239 +) +Fair Value Measurements at +December 31, 2016 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil and natural gas derivatives +$ +— +$ +(24,954 +) +$ +— +$ +(24,954 +) +Total +$ +— +$ +(24,954 +) +$ +— +$ +(24,954 +) +Additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 12 — FAIR VALUE MEASUREMENTS — Continued +Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2017 and 2016 . The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions. +NOTE 13 — COMMITMENTS AND CONTINGENCIES +Office Lease +The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026 . The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease. +From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties. +The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2017 (in thousands). +Year Ending December 31, +Amount +2018 +$ +2,495 +2019 +2,528 +2020 +2,602 +2021 +2,660 +2022 +2,774 +Thereafter +9,561 +Total +$ +22,620 +Rent expense, including fees for operating expenses and consumption of electricity, was $2.6 million , $2.9 million and $1.7 million for 2017 , 2016 and 2015 , respectively. +Processing, Transportation and Salt Water Disposal Commitments +Delaware Basin — Loving County, Texas Natural Gas Processing +In late 2015, the Company entered into a 15 -year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2017 , the total deficiency fee required to be paid would be approximately $8.4 million . In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $14.4 million and $9.8 million in processing and gathering fees under this agreement during the years ended December 31, 2017 and 2016 , respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants. +Delaware Basin — Eddy County, New Mexico Natural Gas Transportation +In late 2017, the Company entered into an 18 -year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue natural gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this agreement, if the Company does not meet the volume commitment for transportation in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued +contractual obligation at December 31, 2017 was approximately $59.4 million . The Company paid approximately $0.2 million in transportation fees, which included no deficiency fees, under this agreement during the year ended December 31, 2017 . +In late 2017, the Company also entered into a fixed-fee NGL transportation and fractionation agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant. The Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed late in 2019. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company does not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven -year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. The Company’s minimum contractual obligation over the seven -year period containing minimum NGL commitments would be approximately $132.5 million . +Delaware Basin — San Mateo +The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15 -year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at December 31, 2017 was approximately $232.6 million . The Company paid approximately $39.4 million in fees under the Operational Agreements during the year ended December 31, 2017 . +Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed into service in 2018. San Mateo’s total commitments under these agreements are $55.3 million . The subsidiary of San Mateo paid approximately $49.7 million under these agreements during the year ended December 31, 2017 . As of December 31, 2017 , the remaining obligations under these agreements were $5.6 million , which are expected to be incurred within the next year. +On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains All American Pipeline, L.P. (“Plains”) (see Note 18). +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $36.5 million at December 31, 2017 . +At December 31, 2017 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $24.8 million at December 31, 2017 . The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 14 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2017 and 2016 (in thousands). +December 31, +2017 +2016 +Accrued evaluated and unproved and unevaluated property costs +$ +105,347 +$ +54,273 +Accrued support equipment and facilities costs +14,823 +15,139 +Accrued lease operating expenses +12,611 +16,009 +Accrued interest on debt +8,345 +6,541 +Accrued asset retirement obligations +1,176 +915 +Accrued partners’ share of joint interest charges +27,628 +5,572 +Other +4,418 +3,011 +Total accrued liabilities +$ +174,348 +$ +101,460 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2017, 2016 and 2015 (in thousands). +Year Ended December 31, +2017 +2016 +2015 +Cash paid for income taxes +$ +— +$ +2,895 +$ +506 +Cash paid for interest expense, net of amounts capitalized +$ +32,760 +$ +27,464 +$ +16,154 +Increase in asset retirement obligations related to mineral properties +$ +4,385 +$ +3,817 +$ +2,510 +(Decrease) increase in asset retirement obligations related to support equipment and facilities +$ +(60 +) +$ +222 +$ +383 +Increase (decrease) in liabilities for oil and natural gas properties capital expenditures +$ +48,929 +$ +1,775 +$ +(30,683 +) +(Decrease) increase in liabilities for support equipment and facilities +$ +(955 +) +$ +(588 +) +$ +12,076 +Issuance of restricted stock units for director and advisor services +$ +— +$ +992 +$ +584 +Stock-based compensation expense recognized as liability +$ +362 +$ +569 +$ +79 +(Decrease) increase in liabilities for accrued cost to issue equity +$ +(343 +) +$ +343 +$ +— +Transfer of inventory (to) from oil and natural gas properties +$ +(374 +) +$ +395 +$ +615 +Transfer of inventory to midstream and other property and equipment +$ +(317 +) +$ +— +$ +— +NOTE 15 — SUBSIDIARY GUARANTORS +On April 14, 2015, Matador issued the Original Notes and on December 9, 2016, Matador issued the Additional Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). Matador filed a registration statement on Form S-3 with the SEC on August 11, 2017, which became effective upon filing, registering, among other securities, senior and subordinated debt securities and guarantees of debt securities by the Guarantor Subsidiaries. At December 31, 2017 , the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes. +The following presents condensed consolidating financial information of the issuer (Matador), the Non-Guarantor Subsidiaries, the Guarantor Subsidiaries and all entities on a consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 15 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Balance Sheet +December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +ASSETS +Intercompany receivable +$ +585,109 +$ +2,912 +$ +— +$ +(588,021 +) +$ +— +Third-party current assets +2,240 +9,334 +245,596 +— +257,170 +Net property and equipment +— +223,178 +1,658,278 +— +1,881,456 +Investment in subsidiaries +1,147,295 +— +111,077 +(1,258,372 +) +— +Third-party long-term assets +6,425 +— +3,642 +(3,003 +) +7,064 +Total assets +$ +1,741,069 +$ +235,424 +$ +2,018,593 +$ +(1,849,396 +) +$ +2,145,690 +LIABILITIES AND EQUITY +Intercompany payable +$ +— +$ +— +$ +588,021 +$ +(588,021 +) +$ +— +Third-party current liabilities +8,847 +19,891 +254,142 +(274 +) +282,606 +Senior unsecured notes payable +574,073 +— +— +— +574,073 +Other third-party long-term liabilities +1,593 +3,466 +29,135 +(2,729 +) +31,465 +Total equity attributable to Matador Resources Company +1,156,556 +111,077 +1,147,295 +(1,258,372 +) +1,156,556 +Non-controlling interest in subsidiaries +— +100,990 +— +— +100,990 +Total liabilities and equity +$ +1,741,069 +$ +235,424 +$ +2,018,593 +$ +(1,849,396 +) +$ +2,145,690 +Condensed Consolidating Balance Sheet +December 31, 2016 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +ASSETS +Intercompany receivable +$ +316,791 +$ +3,571 +$ +12,091 +$ +(332,453 +) +$ +— +Third-party current assets +101,102 +4,242 +173,838 +— +279,182 +Net property and equipment +33 +113,107 +1,071,385 +— +1,184,525 +Investment in subsidiaries +856,762 +— +90,275 +(947,037 +) +— +Third-party long-term assets +— +— +958 +— +958 +Total assets +$ +1,274,688 +$ +120,920 +$ +1,348,547 +$ +(1,279,490 +) +$ +1,464,665 +LIABILITIES AND EQUITY +Intercompany payable +$ +— +$ +12,091 +$ +320,362 +$ +(332,453 +) +$ +— +Third-party current liabilities +9,265 +16,632 +143,608 +— +169,505 +Senior unsecured notes payable +573,924 +— +— +— +573,924 +Other third-party long-term liabilities +1,374 +602 +27,815 +— +29,791 +Total equity attributable to Matador Resources Company +690,125 +90,275 +856,762 +(947,037 +) +690,125 +Non-controlling interest in subsidiaries +— +1,320 +— +— +1,320 +Total liabilities and equity +$ +1,274,688 +$ +120,920 +$ +1,348,547 +$ +(1,279,490 +) +$ +1,464,665 +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 15 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +47,883 +$ +531,508 +$ +(35,115 +) +$ +544,276 +Total expenses +5,610 +21,260 +391,680 +(35,115 +) +383,435 +Operating (loss) income +(5,610 +) +26,623 +139,828 +— +160,841 +Net gain on asset sales and inventory impairment +— +— +23 +— +23 +Interest expense +(34,565 +) +— +— +— +(34,565 +) +Other income +27 +37 +3,487 +— +3,551 +Earnings in subsidiaries +157,589 +— +14,251 +(171,840 +) +— +Income before income taxes +117,441 +26,660 +157,589 +(171,840 +) +129,850 +Total income tax (benefit) provision +(8,426 +) +269 +— +— +(8,157 +) +Net income attributable to non-controlling interest in subsidiaries +— +(12,140 +) +— +— +(12,140 +) +Net income attributable to Matador Resources Company shareholders +$ +125,867 +$ +14,251 +$ +157,589 +$ +(171,840 +) +$ +125,867 +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2016 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +17,302 +$ +257,828 +$ +(10,708 +) +$ +264,422 +Total expenses +5,319 +7,031 +439,947 +(10,708 +) +441,589 +Operating (loss) income +(5,319 +) +10,271 +(182,119 +) +— +(177,167 +) +Net gain on asset sales and inventory impairment +— +— +107,277 +— +107,277 +Interest expense +(28,199 +) +— +— +— +(28,199 +) +Other expense +— +— +(4 +) +— +(4 +) +(Loss) earnings in subsidiaries +(64,349 +) +— +9,810 +54,539 +— +(Loss) income before income taxes +(97,867 +) +10,271 +(65,036 +) +54,539 +(98,093 +) +Total income tax (benefit) provision +(446 +) +97 +(687 +) +— +(1,036 +) +Net income attributable to non-controlling interest in subsidiaries +— +(364 +) +— +— +(364 +) +Net (loss) income attributable to Matador Resources Company shareholders +$ +(97,421 +) +$ +9,810 +$ +(64,349 +) +$ +54,539 +$ +(97,421 +) +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2015 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +6,310 +$ +316,067 +$ +(4,344 +) +$ +318,033 +Total expenses +5,739 +2,944 +1,120,356 +(4,344 +) +1,124,695 +Operating (loss) income +(5,739 +) +3,366 +(804,289 +) +— +(806,662 +) +Net gain on asset sales and inventory impairment +— +— +908 +— +908 +Interest expense +(20,511 +) +— +(1,243 +) +— +(21,754 +) +Other income +— +— +616 +— +616 +(Loss) earnings in subsidiaries +(658,698 +) +— +2,458 +656,240 +— +(Loss) income before income taxes +(684,948 +) +3,366 +(801,550 +) +656,240 +(826,892 +) +Total income tax (benefit) provision +(5,163 +) +647 +(142,852 +) +— +(147,368 +) +Net income attributable to non-controlling interest in subsidiaries +— +(261 +) +— +— +(261 +) +Net (loss) income attributable to Matador Resources Company shareholders +$ +(679,785 +) +$ +2,458 +$ +(658,698 +) +$ +656,240 +$ +(679,785 +) +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 15 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +(307,982 +) +$ +21,308 +$ +585,799 +$ +— +$ +299,125 +Net cash provided by (used in) investing activities +33 +(119,922 +) +(597,519 +) +(106,595 +) +(824,003 +) +Net cash provided by (used in) financing activities +208,440 +96,307 +(2,843 +) +106,595 +408,499 +Decrease in cash +(99,509 +) +(2,307 +) +(14,563 +) +— +(116,379 +) +Cash at beginning of year +99,795 +2,307 +110,782 +— +212,884 +Cash at end of year +$ +286 +$ +— +$ +96,219 +$ +— +$ +96,505 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2016 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +(45,215 +) +$ +6,694 +$ +172,607 +$ +— +$ +134,086 +Net cash used in investing activities +(324,724 +) +(64,683 +) +(401,034 +) +384,801 +(405,640 +) +Net cash provided by financing activities +469,654 +60,110 +322,743 +(384,801 +) +467,706 +Increase in cash +99,715 +2,121 +94,316 +— +196,152 +Cash at beginning of year +80 +186 +16,466 +— +16,732 +Cash at end of year +$ +99,795 +$ +2,307 +$ +110,782 +$ +— +$ +212,884 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2015 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +(31,271 +) +$ +13,916 +$ +225,890 +$ +— +$ +208,535 +Net cash used in investing activities +(546,715 +) +(31,101 +) +(410,843 +) +563,505 +(425,154 +) +Net cash provided by financing activities +577,973 +17,353 +193,123 +(563,505 +) +224,944 +(Decrease) increase in cash +(13 +) +168 +8,170 +— +8,325 +Cash at beginning of year +93 +18 +8,296 +— +8,407 +Cash at end of year +$ +80 +$ +186 +$ +16,466 +$ +— +$ +16,732 +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 16 — RELATED PARTY TRANSACTIONS +In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2017 , the Company had contributed an aggregate of approximately $4.4 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. +NOTE 17 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, natural gas, oil and salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 5). +The following tables present selected financial information for the periods presented regarding the Company’s operating segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2017 +Oil and natural gas revenues +$ +525,862 +$ +2,822 +$ +— +$ +— +$ +528,684 +Midstream services revenues +— +47,037 +— +(36,839 +) +10,198 +Realized loss on derivatives +(4,321 +) +— +— +— +(4,321 +) +Unrealized gain on derivatives +9,715 +— +— +— +9,715 +Expenses (1) +333,923 +23,420 +62,931 +(36,839 +) +383,435 +Operating income (loss) (2) +$ +197,333 +$ +26,439 +$ +(62,931 +) +$ +— +$ +160,841 +Total assets +$ +1,768,393 +$ +257,871 +$ +119,426 +$ +— +$ +2,145,690 +Capital expenditures (3) +$ +753,157 +$ +114,113 +$ +5,688 +$ +— +$ +872,958 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million . +(2) +Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 17 — SEGMENT INFORMATION — Continued +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2016 +Oil and natural gas revenues +$ +289,512 +$ +1,644 +$ +— +$ +— +$ +291,156 +Midstream services revenues +— +18,982 +— +(13,764 +) +5,218 +Realized gain on derivatives +9,286 +— +— +— +9,286 +Unrealized loss on derivatives +(41,238 +) +— +— +— +(41,238 +) +Expenses (1) +391,098 +8,254 +56,001 +(13,764 +) +441,589 +Operating (loss) income (2) +$ +(133,538 +) +$ +12,372 +$ +(56,001 +) +$ +— +$ +(177,167 +) +Total assets +$ +1,098,525 +$ +140,459 +$ +225,681 +$ +— +$ +1,464,665 +Capital expenditures +$ +379,881 +$ +67,566 +$ +6,913 +$ +— +$ +454,360 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment. +(2) +Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2015 +Oil and natural gas revenues +$ +277,844 +$ +496 +$ +— +$ +— +$ +278,340 +Midstream services revenues +— +11,485 +— +(9,621 +) +1,864 +Realized gain on derivatives +77,094 +— +— +— +77,094 +Unrealized loss on derivatives +(39,265 +) +— +— +— +(39,265 +) +Expenses (1) +1,078,534 +5,178 +50,604 +(9,621 +) +1,124,695 +Operating (loss) income (2) +$ +(762,861 +) +$ +6,803 +$ +(50,604 +) +$ +— +$ +(806,662 +) +Total assets +$ +1,000,075 +$ +75,980 +$ +64,806 +$ +— +$ +1,140,861 +Capital expenditures (3) +$ +622,642 +$ +75,009 +$ +786 +$ +— +$ +698,437 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $176.7 million and $1.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.5 million and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment. +(2) +Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +In October 2015, the Company sold the Loving County Processing System to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2017, 2016 and 2015 +NOTE 18 — SUBSEQUENT EVENTS +On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains to gather and transport crude oil for the Company and third-party customers in and around the Rustler Breaks asset area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase Matador’s oil production in the Rustler Breaks asset area and in the Wolf asset area in Loving County, Texas. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2017, 2016 and 2015 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015 (in thousands). +Year Ended December 31, +2017 +2016 +2015 +Property acquisition costs +Proved +$ +45,270 +$ +— +$ +16,524 +Unproved and unevaluated +214,662 +108,206 +253,923 +Exploration costs +167,213 +113,562 +122,495 +Development costs +326,012 +158,113 +229,700 +Total costs incurred (1) +$ +753,157 +$ +379,881 +$ +622,642 +__________________ +(1) +Excludes midstream-related development and corporate costs of approximately $119.8 million, $74.5 million and $75.8 million for the years ended December 31, 2017, 2016 and 2015 , respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2017, 2016 and 2015 , most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $4.8 million , $4.4 million and $3.3 million for the years ended December 31, 2017, 2016 and 2015 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $23.1 million , $15.7 million and $6.9 million of these internal costs for the years ended December 31, 2017 , 2016 and 2015 , respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $7.3 million , $3.7 million and $3.9 million of its interest expense for the years ended December 31, 2017 , 2016 and 2015 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2017, 2016 and 2015 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2017, 2016 and 2015 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2017, 2016 and 2015 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2014 +24,184 +267,055 +68,693 +Revisions of prior estimates +(2,609 +) +(75,433 +) +(15,181 +) +Purchases of minerals-in-place +1,102 +2,927 +1,589 +Extensions and discoveries +27,459 +70,054 +39,135 +Production +(4,492 +) +(27,702 +) +(9,109 +) +Total at December 31, 2015 +45,644 +236,901 +85,127 +Revisions of prior estimates +(6,440 +) +(28,481 +) +(11,187 +) +Extensions and discoveries +22,869 +114,730 +41,992 +Production +(5,096 +) +(30,501 +) +(10,180 +) +Total at December 31, 2016 +56,977 +292,649 +105,752 +Revisions of prior estimates +3,847 +34,395 +9,580 +Purchases of minerals-in-place +5,257 +7,348 +6,482 +Extensions and discoveries +28,513 +99,935 +45,169 +Production +(7,851 +) +(38,163 +) +(14,212 +) +Total at December 31, 2017 +86,743 +396,164 +152,771 +Proved Developed Reserves +December 31, 2014 +14,053 +102,795 +31,185 +December 31, 2015 +17,129 +101,447 +34,037 +December 31, 2016 +22,604 +126,759 +43,731 +December 31, 2017 +36,966 +190,109 +68,651 +Proved Undeveloped Reserves +December 31, 2014 +10,131 +164,260 +37,508 +December 31, 2015 +28,515 +135,454 +51,090 +December 31, 2016 +34,373 +165,890 +62,021 +December 31, 2017 +49,777 +206,055 +84,120 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2017, 2016 and 2015 . +The Company’s proved oil and natural gas reserves increased to 152,771 MBOE at December 31, 2017 from 105,752 MBOE at December 31, 2016 . The Company’s proved oil and natural gas reserves increased by 61,231 MBOE and the Company produced 14,212 MBOE during the year ended December 31, 2017 , resulting in a net increase of 47,019 MBOE. An increase of 45,169 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 9,580 MBOE during 2017 as a result of revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves in 2017, as compared to 2016. The Company also added 6,482 MBOE in proved oil and natural gas reserves in 2017 as a result of purchases of minerals-in-place in the Delaware Basin. The Company’s proved developed oil and natural gas reserves increased to 68,651 MBOE at December 31, 2017 from 43,731 MBOE at December 31, 2016 , primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2017 , the Company’s proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 105,752 MBOE at December 31, 2016 from 85,127 MBOE at December 31, 2015. The Company’s proved oil and natural gas reserves increased by 30,805 MBOE and the Company produced 10,180 MBOE during the year ended December 31, 2016, resulting in a net increase of 20,625 MBOE. An +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2017, 2016 and 2015 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +increase of 41,992 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 11,187 MBOE during 2016 as a result of the reclassification of proved undeveloped reserves to contingent resources, primarily due to the decline in weighted average commodity prices used to estimate proved reserves during 2016, as compared to 2015. The Company’s proved developed oil and natural gas reserves increased to 43,731 MBOE at December 31, 2016 from 34,037 MBOE at December 31, 2015, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2016, the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 41% proved developed and approximately 59% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from 68,693 MBOE at December 31, 2014. The Company’s proved oil and natural gas reserves increased by 25,543 MBOE and the Company produced 9,109 MBOE during the year ended December 31, 2015, resulting in a net increase of 16,434 MBOE. An increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the removal of 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015, as well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves, primarily in the Haynesville shale in Northwest Louisiana, primarily resulting from the decline in commodity prices during 2015. The Company also purchased minerals-in-place with proved reserves of 1,589 MBOE in 2015, primarily as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to 34,037 MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and the Eagle Ford shale and the conversion of previously undeveloped natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2015, the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately 60% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2017 , the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , the comparable average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , the comparable average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2017, 2016 and 2015 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2017, 2016 and 2015 (in thousands). +Year Ended December 31, +2017 +2016 +2015 +Future cash inflows +$ +5,249,116 +$ +2,684,877 +$ +2,461,131 +Future production costs +(1,759,495 +) +(927,725 +) +(843,117 +) +Future development costs +(1,029,105 +) +(630,280 +) +(615,692 +) +Future income tax expense +(228,622 +) +(24,742 +) +(43,956 +) +Future net cash flows +2,231,894 +1,102,130 +958,366 +10% annual discount for estimated timing of cash flows +(973,248 +) +(527,087 +) +(429,185 +) +Standardized measure of discounted future net cash flows +$ +1,258,646 +$ +575,043 +$ +529,181 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2017, 2016 and 2015 (in thousands). +Year Ended December 31, +2017 +2016 +2015 +Balance, beginning of period +$ +575,043 +$ +529,181 +$ +913,319 +Net change in sales and transfer prices and in production (lifting) costs related to future production +374,370 +(92,477 +) +(509,901 +) +Changes in estimated future development costs +(298,504 +) +(74,142 +) +(145,861 +) +Sales and transfers of oil and natural gas produced during the period +(403,095 +) +(191,908 +) +(184,612 +) +Purchases of reserves in place +97,225 +— +16,321 +Net change due to extensions and discoveries +677,681 +360,033 +401,895 +Net change due to revisions in estimates of reserves quantities +143,749 +(95,917 +) +(285,823 +) +Previously estimated development costs incurred during the period +151,974 +84,519 +121,543 +Accretion of discount +54,623 +51,779 +82,574 +Other +(3,929 +) +(1,962 +) +2,029 +Net change in income taxes +(110,491 +) +5,937 +117,697 +Standardized measure of discounted future net cash flows +$ +1,258,646 +$ +575,043 +$ +529,181 +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2017, 2016 and 2015 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2017 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2017 +Oil and natural gas revenues +$ +165,125 +$ +134,948 +$ +113,764 +$ +114,847 +Third-party midstream services revenues +3,326 +3,218 +2,099 +1,555 +Realized (loss) gain on derivatives +(3,145 +) +485 +558 +(2,219 +) +Unrealized (loss) gain on derivatives +(11,734 +) +(12,372 +) +13,190 +20,631 +Expenses +112,547 +99,730 +90,622 +80,536 +Other expense +(6,741 +) +(8,570 +) +(7,302 +) +(8,378 +) +Income before income taxes +34,284 +17,979 +31,687 +45,900 +Income tax benefit +(8,157 +) +— +— +— +Net income +42,441 +17,979 +31,687 +45,900 +Net income attributable to non-controlling interest in subsidiaries +(4,106 +) +(2,940 +) +(3,178 +) +(1,916 +) +Net income attributable to +Matador Resources Company shareholders +$ +38,335 +$ +15,039 +$ +28,509 +$ +43,984 +Earnings per common share +Basic +$ +0.36 +$ +0.15 +$ +0.28 +$ +0.44 +Diluted +$ +0.35 +$ +0.15 +$ +0.28 +$ +0.44 +The following table presents selected unaudited quarterly financial information for 2016 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2016 +Oil and natural gas revenues +$ +94,815 +$ +83,079 +$ +69,336 +$ +43,926 +Third-party midstream services revenues +2,261 +1,566 +918 +473 +Realized (loss) gain on derivatives +(1,127 +) +885 +2,465 +7,063 +Unrealized (loss) gain on derivatives +(10,977 +) +3,203 +(26,625 +) +(6,839 +) +Expenses (1) +76,753 +71,879 +146,705 +146,252 +Other income (expense) (2) +96,196 +(5,948 +) +(5,136 +) +(6,038 +) +Income (loss) before income taxes +104,415 +10,906 +(105,747 +) +(107,667 +) +Income tax provision (benefit) +105 +(1,141 +) +— +— +Net income (loss) +104,310 +12,047 +(105,747 +) +(107,667 +) +Net (income) loss attributable to non-controlling interest in subsidiaries +(155 +) +(116 +) +(106 +) +13 +Net income (loss) attributable to +Matador Resources Company shareholders +$ +104,155 +$ +11,931 +$ +(105,853 +) +$ +(107,654 +) +Earnings (loss) per common share +Basic +$ +1.10 +$ +0.13 +$ +(1.15 +) +$ +(1.26 +) +Diluted +$ +1.09 +$ +0.13 +$ +(1.15 +) +$ +(1.26 +) +__________________ +(1) +Expenses for June 30 and March 31, 2016 included full-cost ceiling impairment charges of $78.2 million and $80.5 million, respectively. +(2) +Other income (expense) for December 31, 2016 included gain on the sale of the Loving County Processing System of $104.1 million. See Note 5. +F-43 \ No newline at end of file diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/filing_metadata.csv b/raw/filings/0001520006/2017/0001520006-18-000053/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..3e596d1a1e8f52a2c2edfe53acf36aaec18c76fa --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2018-03-01,2017-12-31,2018-03-01T07:42:59.000Z,0001520006-18-000053,a20171231mtdr10-k.htm,10-K,14071327,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000152000618000053/a20171231mtdr10-k.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000618000053/,2017,2017,1 diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/item1.txt b/raw/filings/0001520006/2017/0001520006-18-000053/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..00d1a846855a77d33e57c5634de6cab786660e80 --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/item1.txt @@ -0,0 +1,1276 @@ +Item 1. Business. +In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2017 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also continued to increase our leasehold position in the Delaware Basin. In addition, we concluded several important transactions in 2017 , including the formation of San Mateo in February 2017, the October 2017 public offering of 8,000,000 shares of our +2 +Table of Contents +common stock and multiple increases in the borrowing base under our Credit Agreement (as defined below). These transactions increased our operational flexibility and opportunities and further strengthened our balance sheet. +For information about our segment reporting, see Note 17 to the consolidated financial statements in this Annual Report. +2017 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2017 , we achieved record oil, natural gas and average daily oil equivalent production. In 2017 , we produced 7.9 million Bbl of oil, an increase of 54% , as compared to 5.1 million Bbl of oil produced in 2016 . We also produced 38.2 Bcf of natural gas, an increase of 25% from 30.5 Bcf of natural gas produced in 2016 . Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, an increase of 40% , as compared to 27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, for the year ended December 31, 2016 . The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2017 , but also to production from five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Oil production comprised 55% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2017 , as compared to 50% for the year ended December 31, 2016 . +Increased Oil and Oil Equivalent Reserves +At December 31, 2017 , our estimated total proved oil and natural gas reserves were 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, an increase of 44% from 105.8 million BOE, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, at December 31, 2016 . The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 119% and 129% to $1.26 billion and $1.33 billion , respectively, at December 31, 2017 , from $575.0 million and $581.5 million , respectively, at December 31, 2016 , primarily as a result of our ongoing delineation and development drilling activities in the Delaware Basin. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 52% to 86.7 million Bbl at December 31, 2017 from 57.0 million Bbl at December 31, 2016 . Our proved natural gas reserves increased 35% to 396.2 Bcf at December 31, 2017 from 292.6 Bcf at December 31, 2016 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2017 . +At December 31, 2017 , proved developed reserves included 37.0 million Bbl of oil and 190.1 Bcf of natural gas, and proved undeveloped reserves included 49.8 million Bbl of oil and 206.1 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 45% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2017 . Proved developed reserves and proved oil reserves comprised 41% and 54% , respectively, of our total proved oil and natural gas reserves at December 31, 2016 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past four years, as we continue to apply what we learned from our Eagle Ford shale and Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2018. +3 +Table of Contents +We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin in 2017, including 65 gross (56.1 net) operated and 21 gross (3.5 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2017 . As a result, at December 31, 2017 , our total acreage position in the Delaware Basin had increased to approximately 199,600 gross ( 114,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been pleased with the aggregate performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our seven main asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 85% to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 MMcf of natural gas per day ( 66% of total natural gas production), in 2017 , as compared to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 . We expect our Delaware Basin production to increase throughout 2018 as we continue the delineation and development of these asset areas. +Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2017 included: +• +in our Rustler Breaks asset area, the extension of Wolfcamp A-XY operations to the northwest region of the asset area, the initial testing of the Wolfcamp A-Lower interval and the continued delineation and development of previously tested horizons; +• +in our Jackson Trust asset area, the results from the Totum E 18-TTT-C24 NL #211H well, whose 24-hour initial potential test result and subsequent well performance marked the best result we have achieved in the Wolfcamp A-Lower interval in either the Wolf or Jackson Trust asset areas; +• +in our Wolf asset area, a positive first test of the Wolfcamp B interval; +• +in our Ranger asset area, the continued success of the three wells drilled and completed in the Third Bone Spring formation on our Mallon leasehold, which were placed on gas lift during the third quarter of 2017 and have together produced over 1.1 million Bbl of oil in just over one year of production; +• +in our Twin Lakes asset area, a positive test of the Wolfcamp D formation from the D. Culbertson 26-15S-36E TL State #234H well, our first horizontal well in the Twin Lakes asset area; +• +in our Arrowhead asset area, the drilling and completion of our first operated wells, which further illustrated the potential of the Second Bone Spring and the Third Bone Spring in our northern Delaware Basin acreage position; +• +in our Antelope Ridge asset area, the drilling of our first two operated wells, the first of which was completed in early 2018 and was a positive test of the Wolfcamp A interval that we believe confirms the prospectivity of the Antelope Ridge asset area; and +• +the significant progress made in our midstream operations, including (i) the ongoing expansion of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”), (ii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas and (iii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks and Wolf asset areas, significantly increasing San Mateo’s salt water disposal capacity in these asset areas. +We also completed and began producing oil and natural gas from eight gross (5.8 net) wells in the Eagle Ford shale in South Texas in 2017 , including five gross (5.0 net) operated and three gross (0.8 net) non-operated wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017 , although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that began producing in 2017 . +Financing Arrangements +On October 10, 2017 , we completed a public offering of 8,000,000 shares of our common stock, receiving proceeds of approximately $208.7 million (before expenses). A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, leasehold and mineral acquisitions and general corporate purposes, including to fund a portion of our current and future capital expenditures. +4 +Table of Contents +Midstream Joint Venture +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo. Through January 31, 2018, we had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018 and may earn up to an additional $58.8 million in performance incentives over the next four years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo continues to provide firm capacity service to us at market rates, while also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas. +2018 Recent Developments +On January 22, 2018, we announced a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains All American Pipeline, L.P. (“Plains”) to gather and transport crude oil for us and third-party customers in and around the Rustler Breaks asset area. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase our oil production in the Rustler Breaks and Wolf asset areas. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During 2017 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our asset areas by exploring for more conventional targets as well, although for the year ended December 31, 2017 , essentially all of our efforts were focused on unconventional plays. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2017 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +199,600 +114,000 +450 +211.5 +4,630 +1,957.7 +128,999 +40.6 +29,463 +South Texas: +Eagle Ford (5) +31,800 +29,000 +142 +119.8 +241 +208.5 +12,346 +72.2 +4,413 +Northwest Louisiana/East Texas: +Haynesville +19,600 +12,000 +217 +20.5 +413 +102.0 +10,106 +59.5 +4,697 +Cotton Valley (6) +21,100 +18,600 +81 +54.3 +71 +50.0 +1,320 +100.0 +363 +Area Total (7) +25,500 +22,800 +298 +74.8 +484 +152.0 +11,426 +64.1 +5,060 +Total +256,900 +165,800 +890 +406.1 +5,355 +2,318.2 +152,771 +44.9 +38,936 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2017 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2017 , these engineered drilling locations included only 261 gross (130.5 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations in the Delaware Basin, 12 gross (12.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and nine gross (3.3 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. +5 +Table of Contents +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Production volumes and proved reserves reported in two streams; oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2017 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2017 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2017 , we also were the operator for approximately 94% of our Eagle Ford acreage and approximately 64% of our Haynesville acreage, including approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by an affiliate of Chesapeake Energy Corporation. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced hydraulic fracturing techniques. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +As noted above in “— 2017 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2017 , and as a result, at December 31, 2017 , our total acreage position in Southeast New Mexico and West Texas was approximately 199,600 gross ( 114,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 28,800 gross (15,500 net) acres in our Ranger asset area in Lea County, 56,600 gross (23,400 net) acres in our Arrowhead asset area in Eddy County, 41,000 gross (21,200 net) acres in our Rustler Breaks asset area in Eddy County, 12,000 gross (8,900 net) acres in our Antelope Ridge asset area in Lea County, 13,600 gross (9,400 net) acres in our Wolf and Jackson Trust asset areas in Loving County and 46,100 gross (34,400 net) acres in our Twin Lakes asset area in Lea County at December 31, 2017 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka +6 +Table of Contents +and Morrow formations. At December 31, 2017 , our acreage position in the Delaware Basin was approximately 45% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical and one horizontal well, our acreage position in the Delaware Basin was approximately 59% held by existing production at December 31, 2017 . +During the year ended December 31, 2017 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 86 gross (59.6 net) wells in the Delaware Basin, including 65 gross (56.1 net) operated wells and 21 gross (3.5 net) non-operated wells, throughout our various asset areas. At December 31, 2017 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2017 . Our average daily oil equivalent production from the Delaware Basin increased approximately 85% to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 MMcf of natural gas per day ( 66% of total natural gas production), in 2017 , as compared to 15,941 BOE per day ( 57% of total oil equivalent production), including 10,395 Bbl of oil per day ( 75% of total oil production) and 33.3 MMcf of natural gas per day ( 40% of total natural gas production), in 2016 . Our average daily oil equivalent production from the Delaware Basin also grew approximately 69% from 20,670 BOE per day in the fourth quarter of 2016 to 34,859 BOE per day in the fourth quarter of 2017 . +At December 31, 2017 , approximately 84% of our estimated total proved oil and natural gas reserves, or 129.0 million BOE, was attributable to the Delaware Basin, including approximately 77.5 million Bbl of oil and 308.9 Bcf of natural gas, a 62% increase, as compared to 79.4 million BOE for the year ended December 31, 2016 . Our Delaware Basin proved reserves at December 31, 2017 comprised approximately 89% of our proved oil reserves and 78% of our proved natural gas reserves, as compared to approximately 82% of our proved oil reserves and 67% of our proved natural gas reserves at December 31, 2016 . +At December 31, 2017 , we had identified 4,630 gross ( 1,957.7 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 2,954 gross (1,775.5 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2017 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our second anticipated operated horizontal test of the Wolfcamp D formation in 2018). Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing and that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible, at December 31, 2017, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2017 , these potential future drilling locations included only 261 gross (130.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, to which we have assigned proved undeveloped reserves. +At December 31, 2017 , we were operating six drilling rigs in the Delaware Basin, and we expect to operate those rigs in the Delaware Basin throughout 2018, including three rigs in the Rustler Breaks asset area, one rig in the Wolf/Jackson Trust asset areas, one rig in the Ranger/Arrowhead and Twin Lakes asset areas and one rig in the Antelope Ridge asset area. One of the three rigs operating in the Rustler Breaks asset area is also expected to drill at least two commercial salt water disposal wells in that area during 2018 for San Mateo. As a result, we expect that this rig will spend only approximately three-quarters of the year drilling oil and natural gas wells. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2018. We have allocated substantially all of our 2018 estimated capital expenditure budget to our drilling and completion program and midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well opportunities. +7 +Table of Contents +Rustler Breaks Asset Area - Eddy County, New Mexico +We operated three drilling rigs in our Rustler Breaks asset area during most of 2017. We completed and turned to sales 53 gross (34.5 net) horizontal wells in the Rustler Breaks asset area in 2017, including 37 gross (32.4 net) operated and 16 gross (2.1 net) non-operated wells. Most of these wells were completed in the Wolfcamp A-XY or Wolfcamp B-Blair intervals, and the well results achieved were consistent with previous wells drilled and completed in those intervals. +One of the key achievements of our drilling and completions program in our Rustler Breaks asset area in 2017 was the success of our wells drilled in the northwestern portion of our acreage position. Early performance from these wells is comparable to or better than Wolfcamp A-XY wells in other portions of our Rustler Breaks asset area. As examples, the Joe Coleman 13-23S-27E RB #206H (Joe Coleman #206H) and the Tom Walters 12-23S-27E RB #203H (Tom Walters #203H) wells tested 1,840 BOE per day (75% oil) and 1,554 BOE per day (74% oil), respectively, during 24-hour initial potential tests. In just nine months of production, the Joe Coleman #206H well has produced approximately 275,000 BOE (71% oil), and in approximately one year of production, the Tom Walters #203H well has produced approximately 255,000 BOE (73% oil). +In addition, two Wolfcamp A-Lower wells completed in 2017 represented our first tests of the Wolfcamp A-Lower interval in the Rustler Breaks asset area. The Guitar 10-24S-28E RB #205H well tested 1,155 BOE per day (75% oil) and the Charlie Sweeney Fed Com #204H well tested 1,188 BOE per day (75% oil), during 24-hour initial potential tests. We believe that these tests confirm the potential of the Wolfcamp A-Lower interval as another completion target in the Rustler Breaks asset area. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY, Wolfcamp A-Lower and Second Bone Spring formations in 2017. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2017, and we completed and turned to sales 13 gross (11.0 net) operated horizontal wells in these asset areas. Most of these wells were completed in the Wolfcamp A-Lower and Second Bone Spring intervals. +In early January 2017, we completed and placed on production the Totum E 18-TTT-C24 NL #211H (Totum #211H) well. This well tested 2,247 BOE per day (72% oil) during a 24-hour initial potential test, which was the highest 24-hour initial potential test for any Wolfcamp A-Lower well completed by us in either our Wolf or Jackson Trust asset areas. We attribute this significant improvement in well performance to both the selection of an improved landing target, identified through the use of 3-D seismic data, and an improved stimulation design. In almost one year of production, the Totum #211H well has produced approximately 300,000 BOE (77% oil). +The Barnett 90-TTT-B01 WF #224H (Barnett #224H) well was our first test of the Wolfcamp B interval in our Wolf asset area. The Barnett #224H well tested 1,803 BOE per day (28% oil) at 4,125 psi during a 24-hour initial potential test. This well exhibited the highest flowing casing pressure on any well yet completed by us in the Wolf asset area. The initial test results and early performance from the Barnett #224H well exceeded our expectations and were similar to those from the Wolfcamp B-Blair interval in the Rustler Breaks asset area. We were pleased with the results of this initial test of the Wolfcamp B interval, which we believe confirms the potential of the Wolfcamp B interval as another completion target in the Wolf asset area. +Arrowhead and Ranger Asset Areas - Eddy and Lea Counties, New Mexico +We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2017. We completed and turned to sales 18 gross (13.4 net) horizontal wells in these asset areas in 2017, including 15 gross (12.7 net) operated and three gross (0.7 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals. +In the second and third quarters of 2017, we completed and turned to sales our first operated horizontal wells in our Arrowhead asset area on our Stebbins leasehold. The Stebbins 20 Federal #123H (Stebbins 20 #123H) well was a Second Bone Spring test, and the Stebbins 20 Federal #133H (Stebbins 20 #133H) well was a Third Bone Spring test. The Stebbins 20 #123H and #133H wells tested 1,010 BOE per day (82% oil) and 1,202 BOE per day (70% oil), respectively, during 24-hour initial potential tests. We completed and turned to sales three additional wells on the Stebbins leasehold in the fourth quarter of 2017, two completed in the Second Bone Spring interval and one completed in the Third Bone Spring interval, with comparable 24-hour initial potential test results to the initial Stebbins wells. +The contiguous nature of the Stebbins acreage has already lent itself to several operational efficiencies, such as batch drilling and completion operations, as well as centralized facilities, each of which contribute to lower overall project costs. Drilling times for the Stebbins wells have improved by as much as 4.1 days since development began on the Stebbins leasehold in 2017. In addition, we expect to be able to drill 1.5 and 2-mile laterals as part of our future development of this acreage. +In the Ranger asset area, we drilled the Airstrip 31-18S-35E RN State Com #132H (Airstrip #132H) well, a Third Bone Spring test north of our Mallon leasehold. The Airstrip #132H well tested 1,263 BOE per day (93% oil) during a 24-hour initial potential test. The Airstrip #132H well has produced approximately 95,000 BOE (92% oil) in its first six months of production. +8 +Table of Contents +During the third quarter of 2017, we installed gas lift on the three Mallon wells—the Mallon 27 Federal Com #1H, #2H and #3H (Mallon #1H, #2H and #3H) wells in the Ranger asset area. Each of these three wells was drilled and completed in the Third Bone Spring and turned to sales in the fourth quarter of 2016. The Mallon wells each tested initially between 2,400 and 2,800 BOE per day (91% oil) and continued to perform well throughout their first ten to eleven months of production prior to the installation of gas lift. Unlike most Third Bone Spring wells completed in the Arrowhead and Ranger asset areas, these wells were tested while flowing up casing (rather than on electrical submersible pump), and the wells continued to flow up casing until the installation of gas lift on each well in the third quarter of 2017. +Each of the Mallon wells exhibited a strong production response to the installation of gas lift. Daily production rates from the Mallon #1H well, which had declined to 600 to 700 Bbl of oil per day, increased to an average of over 1,300 Bbl of oil per day in the first 30 days following gas lift installation. Daily production rates from the Mallon #2H well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of almost 1,500 Bbl of oil per day in the first 30 days following gas lift installation. Daily production rates from the Mallon #3H well, which had declined to 400 to 500 Bbl of oil per day, increased to an average of approximately 900 Bbl of oil per day in the first 30 days following gas lift installation. Natural gas production from these wells responded in a similar fashion. Production declines resumed on these wells at a similar rate to what was observed prior to the installation of gas lift, but from higher daily production rates. The three Mallon wells have produced about 1.3 million BOE (90% oil) in the aggregate, including over 1.1 million Bbl of oil in just over one year of production. +Twin Lakes Asset Area - Lea County, New Mexico +In 2017, we performed our first horizontal test of the Wolfcamp D formation in the eastern portion of our Twin Lakes asset area in northern Lea County, New Mexico. This well, the D. Culbertson 26-15S-36E TL State #234H (D. Culbertson #234H) well, tested approximately 600 BOE per day (82% oil) during a 24-hour initial potential test, including 493 Bbl of oil per day and 640 Mcf of natural gas per day, from a completed lateral length of approximately 4,400 feet. We were pleased and encouraged with the initial results from this discovery well, which we believe confirmed our exploration concept and validated the prospectivity of the Wolfcamp D in the Twin Lakes asset area. To our knowledge, this discovery well is the northernmost horizontal test of the Wolfcamp formation in New Mexico, and this well demonstrates the potential for horizontal exploitation and development of the Wolfcamp formation far to the north of the most active areas of current drilling in the Wolfcamp play in the Delaware Basin. Overall, the D. Culbertson #234H well provided us with a solid first step in our understanding of the Wolfcamp D formation in this area. We plan to drill a second Wolfcamp D test on the western portion of our Twin Lakes acreage position in 2018. +Antelope Ridge Asset Area - Lea County, New Mexico +We drilled our first operated well in the Antelope Ridge asset area, the Florence State 23-23S-34E #202H (Florence #202H) well, in mid-November 2017. This well was completed and turned to sales in January 2018. The Florence #202H well tested 1,947 BOE per day (81% oil) at 1,700 psi during a 24-hour initial potential test. We were pleased with the initial performance of this well and believe it confirms the prospectivity of the Antelope Ridge asset area. We intend to continue the delineation of our acreage position in Antelope Ridge, where other operators in the area have successfully tested the Brushy Canyon, First, Second and Third Bone Spring and Upper Wolfcamp intervals. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2017 , our properties included approximately 31,800 gross ( 29,000 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 86% of our Eagle Ford acreage was held by production at December 31, 2017 , and approximately 98% of our Eagle Ford acreage was either held by production at December 31, 2017 or not burdened by lease expirations before 2019 . +In 2017, we drilled and completed five operated wells in the Eagle Ford shale in South Texas. Two of these wells, the Falls City #1H and #2H wells, both located in Karnes County, were turned to sales in mid-June 2017. The other three wells, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells, all located in La Salle County, were turned to sales in early July 2017. We have a 100% working interest in each of these five wells. These five Eagle Ford shale wells tested +9 +Table of Contents +between approximately 1,100 and 1,700 BOE per day at oil cuts between 90% and 94% during 24-hour initial potential tests. The initial results from this five-well drilling program almost doubled our average daily oil equivalent production from the Eagle Ford shale in the third quarter of 2017, as compared to production levels in the second quarter of 2017. +At December 31, 2017 , the Falls City #1H and #2H wells had the highest estimated ultimate oil recoveries of any of our wells in the Eagle Ford shale. Further, the Martin Ranch C #11H well and the Martin MAK D #49H and D #50H wells were drilled and completed for an average of approximately $4.5 million per well, among the lowest well costs we have achieved in the Eagle Ford shale. Despite not being active in the Eagle Ford shale since the second quarter of 2015, we were able to achieve our fastest drilling time for an Eagle Ford shale well from spud to total depth in one of these Martin Ranch wells. +Our average daily oil equivalent production from the Eagle Ford shale decreased 11% to 4,413 BOE per day, including 3,475 Bbl of oil per day and 5.6 MMcf of natural gas per day, during 2017 , as compared to 4,952 BOE per day, including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016 . For the year ended December 31, 2017 , 11% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During the year ended December 31, 2016 , approximately 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2017 , approximately 8% of our estimated total proved oil and natural gas reserves, or 12.3 million BOE, was attributable to the Eagle Ford shale, including approximately 9.2 million Bbl of oil and 19.0 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 11% of our proved oil reserves and 5% of our proved natural gas reserves at December 31, 2017 , as compared to approximately 18% of our proved oil reserves and 7% of our proved natural gas reserves at December 31, 2016 . +At December 31, 2017 , we had identified 241 gross ( 208.5 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2017 , these 241 gross ( 208.5 net) identified drilling locations included only 12 gross (12.0 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe may be prospective for the Buda formation. At December 31, 2017 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though recent activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals. +Northwest Louisiana and East Texas — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2017 , although we did participate in the drilling and completion of 11 gross (0.6 net) non-operated Haynesville shale wells that were turned to sales in 2017 . We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2018 . +At December 31, 2017 , we held approximately 25,500 gross ( 22,800 net) acres in Northwest Louisiana and East Texas, including 19,600 gross ( 12,000 net) acres in the Haynesville shale play and 21,100 gross (18,600 net) acres in the Cotton Valley +10 +Table of Contents +play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the 13,200 gross ( 6,400 net) acres that we consider to be in the core area of the Haynesville play. We believe the core area of the play includes that area in which the most Haynesville shale wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well from an approximate 5,000-foot horizontal lateral. +For the year ended December 31, 2017 , approximately 13% of our average daily oil equivalent production, or 5,060 BOE per day, including 12 Bbl of oil per day and 30.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 29% of our daily natural gas production for 2017, but oil production from these properties comprised only about 0.1% of our daily oil production during 2017 , as compared to approximately 50% of our daily natural gas production and approximately 0.1% of our daily oil production during 2016 . During the year ended December 31, 2016 , approximately 25% of our average daily oil equivalent production, or 6,920 BOE per day, including 12 Bbl of oil per day and 41.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2017 , approximately 27% of our daily natural gas production, or 28.3 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 2% , or 2.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2016 , approximately 47% of our daily natural gas production, or 39.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 3% , or 2.3 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2017 , approximately 7% of our estimated total proved reserves, or 10.1 million BOE, was attributable to the Haynesville shale with another 1% of our proved reserves, or 1.3 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2017 , we had identified 413 gross ( 102.0 net) engineered locations for potential future drilling in the Haynesville shale play and 71 gross ( 50.0 net) engineered locations for potential future drilling in the Cotton Valley formation. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 413 gross ( 102.0 net) locations identified for future drilling on our Haynesville acreage, 339 gross (49.0 net) locations have been identified within the 13,200 gross ( 6,400 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2017 , these potential future drilling locations included only nine gross (3.3 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Midstream Segment +The midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. Through the ownership and operation of these facilities, we improve our ability to manage costs and control the timing of bringing on new production, and we enhance the value received for our production. As noted above, we contributed the Delaware Midstream Assets to San Mateo in February 2017 and continued to operate them, as well as San Mateo’s other assets, at December 31, 2017 . +Southeast New Mexico and West Texas — Delaware Basin +During 2017, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental 200 MMcf per day to the existing 60 MMcf per day of inlet cryogenic natural gas processing capacity. At February 21, 2018 , the expansion project was proceeding on schedule with the plant expansion expected to become operational by the end of the first quarter of 2018. At December 31, 2017 and February 21, 2018 , the Black River Processing Plant was effectively full with Matador-operated natural gas. The Black River Processing Plant and associated gathering system were built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. It may also provide additional income through the gathering and processing of third-party natural gas after the plant expansion becomes operational. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks. In addition, in October 2017 and January 2018, San Mateo placed into service its second and third, respectively, commercial salt water disposal wells in the Rustler Breaks +11 +Table of Contents +asset area. San Mateo disposed of approximately 7.9 million Bbl of Matador-operated and third-party salt water in the Rustler Breaks asset area during 2017 and, at February 21, 2018 , its salt water disposal wells there had a disposal capacity of approximately 90,000 Bbl of salt water per day. San Mateo plans to add to that disposal capacity in 2018 by upgrading two of the existing salt water disposal wells by installing larger tubing and drilling and completing at least two additional commercial salt water disposal wells and constructing the associated commercial salt water disposal facilities in the Rustler Breaks asset area. We expect these additional wells to be completed in 2018, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to a total of five. At February 21, 2018 , San Mateo was also building out an oil gathering and transportation system in the Rustler Breaks asset area. +In our Wolf asset area in Loving County, Texas, San Mateo has oil, natural gas and salt water gathering systems that gather our oil, natural gas and water production. We retained this three-pipeline system following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo in February 2017. During 2017 , San Mateo disposed of approximately 15.5 million Bbl of salt water in the Wolf asset area, including disposal of third-party salt water on a commercial basis. San Mateo completed its third salt water disposal well in the Wolf asset area during 2017, increasing San Mateo’s disposal capacity in the Wolf asset area to approximately 70,000 Bbl of salt water per day. At February 21, 2018 , San Mateo was also expanding its oil gathering system in the Wolf asset area. +South Texas / Northwest Louisiana and East Texas +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases and from third parties. We also have five non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2017, 2016 and 2015 . +Year Ended December 31, +2017 +2016 +2015 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +7,851 +5,096 +4,492 +Natural gas (Bcf) +38.2 +30.5 +27.7 +Total oil equivalent (MBOE) (1) +14,212 +10,180 +9,109 +Average daily production (BOE/d) (1) +38,936 +27,813 +24,955 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +49.28 +$ +41.19 +$ +45.27 +Oil, with realized derivatives (per Bbl) +$ +48.81 +$ +42.34 +$ +59.13 +Natural gas, without realized derivatives (per Mcf) +$ +3.72 +$ +2.66 +$ +2.71 +Natural gas, with realized derivatives (per Mcf) +$ +3.70 +$ +2.78 +$ +3.24 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +4.10 +$ +4.23 +$ +3.91 +Lease operating +$ +4.74 +$ +5.52 +$ +6.01 +Plant and other midstream services operating +$ +0.92 +$ +0.53 +$ +0.38 +Depletion, depreciation and amortization +$ +12.49 +$ +11.99 +$ +19.63 +General and administrative +$ +4.65 +$ +5.41 +$ +5.50 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +12 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +6,579 +1,268 +— +4 +7,851 +Natural gas (Bcf) +25.1 +2.0 +10.3 +0.8 +38.2 +Total oil equivalent (MBOE) (3) +10,754 +1,611 +1,714 +133 +14,212 +Percentage of total annual net production +75.7 +% +11.3 +% +12.1 +% +0.9 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +18,023 +3,475 +— +12 +21,510 +Natural gas (MMcf/d) +68.6 +5.6 +28.3 +2.1 +104.6 +Total oil equivalent (BOE/d) +29,463 +4,413 +4,697 +363 +38,936 +Average Sales Prices (4) +Oil (per Bbl) +$ +49.08 +$ +50.29 +$ +— +$ +45.52 +$ +49.28 +Natural gas (per Mcf) +$ +4.03 +$ +4.69 +$ +2.83 +$ +2.79 +$ +3.72 +Total oil equivalent (per BOE) +$ +39.41 +$ +45.58 +$ +16.96 +$ +17.69 +$ +37.20 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.80 +$ +10.92 +$ +4.21 +$ +16.77 +$ +6.29 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +3,805 +1,286 +— +5 +5,096 +Natural gas (Bcf) +12.2 +3.1 +14.3 +0.9 +30.5 +Total oil equivalent (MBOE) (3) +5,834 +1,813 +2,385 +148 +10,180 +Percentage of total annual net production +57.3 +% +17.8 +% +23.4 +% +1.5 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +10,395 +3,517 +— +12 +13,924 +Natural gas (MMcf/d) +33.3 +8.6 +39.1 +2.3 +83.3 +Total oil equivalent (BOE/d) +15,941 +4,952 +6,517 +403 +27,813 +Average Sales Prices (4) +Oil (per Bbl) +$ +41.76 +$ +39.49 +$ +— +$ +38.78 +$ +41.19 +Natural gas (per Mcf) +$ +3.15 +$ +3.11 +$ +2.17 +$ +2.27 +$ +2.66 +Total oil equivalent (per BOE) +$ +33.81 +$ +33.46 +$ +13.04 +$ +14.39 +$ +28.60 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +7.32 +$ +12.74 +$ +4.73 +$ +17.07 +$ +7.82 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2015 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +1,697 +2,789 +— +6 +4,492 +Natural gas (Bcf) +4.1 +5.7 +16.9 +1.0 +27.7 +Total oil equivalent (MBOE) (3) +2,379 +3,746 +2,822 +162 +9,109 +Percentage of total annual net production +26.1 +% +41.1 +% +31.0 +% +1.8 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +4,648 +7,642 +— +16 +12,306 +Natural gas (MMcf/d) +11.2 +15.7 +46.4 +2.6 +75.9 +Total oil equivalent (BOE/d) +6,518 +10,263 +7,731 +443 +24,955 +Average Sales Prices (4) +Oil (per Bbl) +$ +43.54 +$ +46.33 +$ +— +$ +43.68 +$ +45.27 +Natural gas (per Mcf) +$ +3.00 +$ +3.17 +$ +2.49 +$ +2.45 +$ +2.71 +Total oil equivalent (per BOE) +$ +36.21 +$ +39.35 +$ +14.97 +$ +15.69 +$ +30.56 +Production Costs (5) +Lease operating, transportation and processing (per BOE) (6) +$ +8.84 +$ +9.25 +$ +4.91 +$ +19.23 +$ +7.90 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +(6) +Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016. +Our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 increased 40% from our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, as compared to 27,813 BOE per day for the year ended December 31, 2016 . Our average daily oil production for the year ended December 31, 2017 was 21,510 Bbl of oil per day, an increase of 54% from 13,924 Bbl of oil per day for the year ended December 31, 2016 . Our average daily natural gas production for the year ended December 31, 2017 was 104.6 MMcf of natural gas per day, an increase of 25% from 83.3 MMcf of natural gas per day for the year ended December 31, 2016 . +Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where, as of December 31, 2016, we had not drilled any new operated wells since the second quarter of 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per day, as compared to 24,955 BOE per day for the year ended December 31, 2015 . Our average daily oil production for the year ended December 31, 2016 was 13,924 Bbl of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year ended December 31, 2015 . Our average daily natural gas production for the year ended December 31, 2016 was 83.3 MMcf of natural gas per day, an increase of 10% from 75.9 MMcf of natural gas per day for the year ended December 31, 2015 . +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2017 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 75% in all wells that we operated at December 31, 2017 . For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 11%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +372 +174.8 +78 +36.7 +450 +211.5 +South Texas: +Eagle Ford (2) +138 +115.8 +4 +4.0 +142 +119.8 +Northwest Louisiana/East Texas: +Haynesville +— +— +217 +20.5 +217 +20.5 +Cotton Valley (3) +2 +2.0 +79 +52.3 +81 +54.3 +Area Total +2 +2.0 +296 +72.8 +298 +74.8 +Total +512 +292.6 +378 +113.5 +890 +406.1 +__________________ +(1) +Includes 217 gross (55.4 net) vertical wells that were acquired in multiple transactions. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2017, 2016 and 2015 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the natural gas liquids (“NGLs”) associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +16 +Table of Contents +At December 31, (1) +2017 +2016 +2015 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +86,743 +56,977 +45,644 +Natural Gas (Bcf) (3) +396.2 +292.6 +236.9 +Total (MBOE) (4) +152,771 +105,752 +85,127 +Estimated proved developed reserves: +Oil (MBbl) +36,966 +22,604 +17,129 +Natural Gas (Bcf) (3) +190.1 +126.8 +101.4 +Total (MBOE) (4) +68,651 +43,731 +34,037 +Percent developed +44.9 +% +41.4 +% +40.0 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +49,777 +34,373 +28,515 +Natural Gas (Bcf) (3) +206.1 +165.9 +135.5 +Total (MBOE) (4) +84,120 +62,021 +51,090 +Standardized Measure (5) (in millions) +$ +1,258.6 +$ +575.0 +$ +529.2 +PV-10 (6) (in millions) +$ +1,333.4 +$ +581.5 +$ +541.6 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas, for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, and for the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) +Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated properties in the Haynesville shale. +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classified proved undeveloped reserves from our total proved reserves in 2016. +(5) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(6) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2017, 2016 and 2015 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2017, 2016 and 2015 were, in millions, $74.8 , $6.5 and $12.4 , respectively. +Our estimated total proved oil and natural gas reserves increase d 44% from 105.8 million BOE at December 31, 2016 to 152.8 million BOE at December 31, 2017 . We added 45.2 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2017, approximately 3.2 times our 2017 annual production of 14.2 million BOE. Our proved oil reserves grew 52% from approximately 57.0 million Bbl at December 31, 2016 to approximately 86.7 million Bbl at December 31, 2017 . Our proved natural gas reserves increase d 35% from 292.6 Bcf at December 31, 2016 to 396.2 Bcf at December 31, 2017 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2017. We incurred approximately 9.6 million BOE in net upward revisions to our proved reserves during 2017 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017, as compared to December 31, 2016. Our proved reserves to production ratio at December 31, 2017 was 10.8 x, an increase of 4% from 10.4 x at December 31, 2016. +17 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increase d 119% from $575.0 million at December 31, 2016 to $1.26 billion at December 31, 2017 . The PV-10 of our total proved oil and natural gas reserves increase d 129% from $581.5 million at December 31, 2016 to $1.33 billion at December 31, 2017 . The increases in our Standardized Measure and PV-10 are primarily a result of our delineation and development operations in the Delaware Basin during 2017 and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2017 , as compared to December 31, 2016 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2017 were $47.79 per Bbl and $2.98 per MMBtu, an increase of 22% and 20% , respectively, as compared to average oil and natural gas prices of $39.25 per Bbl and $2.48 per MMBtu used to estimate proved reserves at December 31, 2016 . Our total proved reserves were made up of 57% oil and 43% natural gas at December 31, 2017 , as compared to 54% oil and 46% natural gas at December 31, 2016 . +Our proved developed oil and natural gas reserves increase d 57% from 43.7 million BOE at December 31, 2016 to 68.7 million BOE at December 31, 2017 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 64% from 22.6 million Bbl at December 31, 2016 to 37.0 million Bbl at December 31, 2017 . Our proved developed natural gas reserves increase d 50% from 126.8 Bcf at December 31, 2016 to 190.1 Bcf at December 31, 2017 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2017 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2016 +43,731 +Extensions and discoveries +14,335 +Purchases of minerals-in-place +1,614 +Revisions of prior estimates +6,375 +Production +(14,212 +) +Conversion of proved undeveloped to proved developed +16,808 +As of December 31, 2017 +68,651 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d 36% from 62.0 million BOE at December 31, 2016 to 84.1 million BOE at December 31, 2017 . Our proved undeveloped oil and natural gas reserves increased from 34.4 million Bbl and 165.9 Bcf, respectively, at December 31, 2016 to 49.8 million Bbl and 206.1 Bcf, respectively, at December 31, 2017 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2017 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2017 within five years of booking these reserves. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2017 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2016 +62,021 +Extensions and discoveries +30,834 +Purchases of minerals-in-place +4,868 +Revisions of prior estimates +3,205 +Conversion of proved undeveloped to proved developed +(16,808 +) +As of December 31, 2017 +84,120 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +The following table sets forth, since 2014, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2014 +3,780 +44.7 +11,223 +$ +201,950 +2015 +2,854 +23.4 +6,747 +104,989 +2016 +4,705 +13.1 +6,883 +94,579 +2017 +9,300 +45.0 +16,808 +211,860 +Total +20,639 +126.2 +41,661 +$ +613,378 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2017 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +77,508 +308.9 +128,999 +$ +1,088.4 +$ +1,153.1 +South Texas: +Eagle Ford (5) +9,189 +19.0 +12,346 +130.6 +138.4 +Northwest Louisiana/East Texas: +Haynesville +— +60.7 +10,106 +35.7 +37.8 +Cotton Valley (6) +46 +7.6 +1,320 +3.9 +4.1 +Area Total +46 +68.3 +11,426 +39.6 +41.9 +Total +86,743 +396.2 +152,771 +$ +1,258.6 +$ +1,333.4 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2017 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2017 were approximately $ 74.8 million . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational +19 +Table of Contents +methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 40 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2017 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +100,500 +50,600 +99,100 +63,400 +199,600 +114,000 +South Texas: +Eagle Ford +27,600 +24,900 +4,200 +4,100 +31,800 +29,000 +Northwest Louisiana/East Texas: +Haynesville +16,200 +8,600 +3,400 +3,400 +19,600 +12,000 +Cotton Valley +17,600 +15,600 +3,500 +3,000 +21,100 +18,600 +Area Total (1) +21,500 +19,300 +4,000 +3,500 +25,500 +22,800 +Total +149,600 +94,800 +107,300 +71,000 +256,900 +165,800 +__________________ +(1) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2017 that will expire over the next four years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2022 and beyond represents an immaterial amount of our overall undeveloped acreage. +20 +Table of Contents +Acres +Acres +Acres +Acres +Expiring 2018 +Expiring 2019 +Expiring 2020 +Expiring 2021 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +25,600 +18,900 +14,400 +11,300 +8,900 +7,800 +19,000 +11,700 +South Texas: +Eagle Ford +900 +700 +1,500 +1,400 +1,600 +1,600 +— +— +Northwest Louisiana/East Texas: +Haynesville +— +— +300 +300 +200 +200 +— +— +Cotton Valley +— +— +— +— +— +— +— +— +Area Total (2) +— +— +300 +300 +200 +200 +— +— +Total +26,500 +19,600 +16,200 +13,000 +10,700 +9,600 +19,000 +11,700 +__________________ +(1) +Approximately 59% of the acreage expiring in the Delaware Basin in the next four years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of the expiring acreage through our 2018 drilling activities or by paying an additional lease bonus, where applicable. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2017 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2017, 2016 and 2015 . +Year Ended December 31, +2017 +2016 +2015 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +72 +43.7 +44 +23.5 +53 +26.7 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +33 +22.3 +28 +15.6 +28 +17.5 +Dry +— +— +— +— +— +— +Total Wells +Productive +105 +66.0 +72 +39.1 +81 +44.2 +Dry +— +— +— +— +— +— +Marketing and Customers +Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. +21 +Table of Contents +The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the years ended December 31, 2017, 2016 and 2015 , we had four, three and three significant purchasers, respectively, that accounted for approximately 60% , 48% and 59% , respectively, of our total oil, natural gas and NGL revenues. Due to the nature of the markets for oil, natural gas and NGLs, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. We expect that some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +22 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s +23 +Table of Contents +jurisdiction under the Interstate Commerce Act, or the ICA. We believed, as of February 21, 2018 , that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and the crude oil pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. +In 2005, Congress enacted the Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +At February 21, 2018 , San Mateo was developing a common carrier pipeline that we expect to be subject to regulation by FERC under the ICA and the Energy Policy Act of 1992, or EP Act. The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +24 +Table of Contents +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors — Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management, or the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have also been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal +25 +Table of Contents +fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the Environmental Protection Agency, or the EPA, has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to +26 +Table of Contents +Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. As of December 31, 2017 , we owned and operated over fifteen underground injection wells and we expect to own and operate similar wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission, or TRC, adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and +27 +Table of Contents +sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2017 , we had 217 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +28 +Table of Contents +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Strategic Planning and Compensation Committee, Corporate Governance Committee, Executive Committee and Nominating Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. \ No newline at end of file diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/item13.txt b/raw/filings/0001520006/2017/0001520006-18-000053/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..75bc618aa33b3508d38f224b21bc771760b75f7a --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. \ No newline at end of file diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/item9a.txt b/raw/filings/0001520006/2017/0001520006-18-000053/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..3f19833ceacd58d39580264ebd1c3f1c8bee7075 --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/item9a.txt @@ -0,0 +1,34 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the three months ended September 30, 2017, we completed the implementation of new accounting and land administration software applications. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change, including procedures to preserve the integrity of the data converted during the application implementations. Additionally, we provided training related to these applications to individuals using the applications to carry out their job responsibilities. We believe the new applications will enhance our internal control over financial reporting due to enhanced automation and integration of related processes. As a result, we have modified the design and documentation of internal control processes and procedures relating to the new applications to complement and supplement existing internal control documentation. The implementation of the new applications was not undertaken in response to any deficiencies in our internal control over financial reporting. +During the three months ended December 31, 2017, we completed the implementation of a new reserves software application. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change, including procedures to preserve the integrity of the data converted during the application implementations. Additionally, we provided training related to this application to individuals using the application to carry out their job responsibilities. We believe this new application will enhance our internal control over financial reporting due to enhanced automation and integration of related processes. We have modified the design and documentation of internal control processes and procedures relating to this new application to complement and supplement existing internal control documentation. The implementation of the new reserves software application was not undertaken in response to any deficiencies in our internal control over financial reporting. +During the three months ended December 31, 2017 , we completed the design and documentation of internal control processes and procedures relating to the new accounting, land administration and reserves software applications. Testing of the controls related to the new applications is completed and is included in the scope of our assessment of our internal control over financial reporting for the year ended December 31, 2017 . +There were no other changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2017 as included herein. +80 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +81 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017 and 2016 , the related statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and our report dated February 28, 2018 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 28, 2018 +82 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/rp_note.txt b/raw/filings/0001520006/2017/0001520006-18-000053/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..363a0e58606947caccf19a10c9cfd534daa3f478 --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/rp_note.txt @@ -0,0 +1,2 @@ +NOTE 16 — RELATED PARTY TRANSACTIONS +In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2017 , the Company had contributed an aggregate of approximately $4.4 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. \ No newline at end of file diff --git a/raw/filings/0001520006/2017/0001520006-18-000053/rpt_disclosure.txt b/raw/filings/0001520006/2017/0001520006-18-000053/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ab374c6eeea97e0c9434c4a06dca25ac7101f32d --- /dev/null +++ b/raw/filings/0001520006/2017/0001520006-18-000053/rpt_disclosure.txt @@ -0,0 +1,108 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2018 there was not, nor was there proposed as of December 31, 2018, any transaction or series of similar transactions to which we +were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the immediate family of any of the +foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation—Compensation Discussion and +Analysis” above. +HEYCO Joint Ventures +In June 2015, the Company entered into two joint ventures (the +“Joint Ventures”) to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of Harvey E. Yates Company. The Company acquired Harvey E. Yates +Company in a 2015 merger (the “HEYCO Merger.”) The HEYCO Affiliates are owned by George M. Yates, who was appointed to the Board on April 28, 2015 in accordance with the terms of the HEYCO Merger, and certain of his affiliates. +Mr. Yates’ term as a director expired at the 2018 Annual Meeting. Pursuant to the terms of the Joint Ventures, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held +by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of +December 31, 2018, the Company had contributed an aggregate of approximately $9.4 million to the two entities. The Company’s contributions are being used to fund capital expenditures associated with the interests owned by the Joint +Ventures as well as to fund acquisitions by the Joint Ventures of other non-operated acreage opportunities. +The Audit +Committee reviewed the terms of the Joint Ventures for potential conflicts of interest under the Company’s related party transaction policy, effective October 12, 2011 (the “Related Party Transaction Policy”), and, after being +fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Joint Ventures, determined that the Joint Ventures were fair to the Company and recommended the Joint Ventures to the full Board for +approval and ratification. The Board subsequently approved and ratified the Joint Ventures. +In addition, in light of Mr. Yates’ ongoing services to HEYCO +Energy Group, Inc., the Board, in accordance with Texas corporate law, adopted resolutions that renounced and provided for a waiver of certain corporate opportunities with respect to Mr. Yates. As a result, during his term on the Board, +Mr. Yates had no fiduciary duty to present certain corporate opportunities related to Mr. Yates’ existing oil and natural gas holdings and/or in areas where Matador did not then operate. +Working Interest and Overriding Royalty Interest Owners +Certain related parties, including Mr. Foran, certain of +Mr. Foran’s affiliated entities (collectively, the “Foran Entities”) and certain HEYCO Affiliates or entities controlled by members of Mr. Yates’ family (the “Yates Entities” and, collectively with the Foran +Entities, the “Interest Owners”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, the +Interest Owners are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Interest Owners are entitled to +receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2018, revenues, net of costs, received by the Yates Entities in their capacities as working interest owners or +overriding royalty interest owners were approximately $10.6 million (the “Yates Net Revenue Payments”). During 2018, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners or overriding +royalty interest owners were approximately $1.7 million (collectively with the Yates Net Revenue Payments, the “Related Net Revenue Payments”). The Related Net Revenue Payments represent approximately 4.5% of our total third-party net +revenue payments during 2018. +2019 +Proxy Statement | Matador Resources Company 79 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +In our capacity as operator, we incur drilling and operating +costs that are billed to our partners based on their respective working interests. During 2018, our joint interest billings to the Yates Entities attributable to their share of costs were approximately $10.8 million (the “Yates +Billings”) and our joint interest billings to the Foran Entities attributable to their share of costs were approximately $0.4 million (collectively with the Yates Billings, the “Related Joint Interest Billings”). The Related +Joint Interest Billings represent approximately 1.3% of our total joint interest billings during 2018. As a result of this ownership by the Interest Owners, from time to time, we will be in a net receivable or net payable position with certain of +the Interest Owners. We do not consider any net receivables from these parties to be uncollectible. +The Audit Committee reviewed the terms of the working interests +and/or overriding royalty interests of the Interest Owners for potential conflicts of interest under the Related Party Transaction Policy, and, after being fully informed as to Mr. Yates’ and Mr. Foran’s respective relationships +and interests in such transactions and all other material facts related to the Related Net Revenue Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest +Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the +transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Certain Employment Relationships +Billy E. Goodwin, Executive Vice President and Head of +Operations, was appointed as an executive officer of the Company in connection with his February 2016 promotion to Senior Vice President—Operations. Two of Mr. Goodwin’s adult children have been employees of the Company since 2014 and +2015, respectively, and each earned in 2018, and are expected to be compensated in 2019, between $120,000 and $700,000. One of Mr. Goodwin’s children has a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa +and over nine years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other child has a Bachelor of Science in Business Administration degree +in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He also has over nine years of industry experience, including as a drilling fluids engineer for a +publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangements for potential conflicts of interest under the Company’s +Related Party Transaction Policy and, after being fully informed as to the employment arrangements and historical and anticipated compensation of Mr. Goodwin’s adult children, and all other material facts related to the relationship, +determined that the employment arrangements were fair to the Company and recommended the employment arrangements to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s sister-in-law +has been an employee of the Company since 2016 and earned in 2018, and is expected to be compensated in 2019, between $120,000 and $250,000. Mr. Baribault’s +sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist University Legal Assistants +Program. She has over 37 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being +fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts +related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment +arrangement. +An adult child of Mr. Foran has been an employee of the Company since 2015 and earned in 2018, and is expected to be compensated in 2019, between +$120,000 and $200,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than eight years of +industry experience, including with another publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment +80 Matador Resources Company | 2019 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +arrangement for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being fully informed as to the employment arrangement and historical and +anticipated compensation of Mr. Foran’s adult child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board +for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +Procedures for Approval of Related +Party Transactions +Pursuant to the Related Party +Transaction Policy, a “Related Party Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, +or any material amendment to any such transaction, involving a Related Party (as defined below) and in which we are a participant, other than: +• +a transaction involving compensation of directors; +• +a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, +change in control provision or agreement or a special supplemental benefit for an executive officer; +• +a transaction available to all employees generally or to all salaried employees generally; +• +a transaction with a Related Party involving less than $120,000; +• +a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity +securities and all holders of that class receive the same benefit on a pro rata basis; or +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that +involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. +“Related Party” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors +or nominees for directors; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, +sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• +any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the +foregoing persons is a general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Party Transaction Policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or +disapproval of the Related Party Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all +material facts of the Related Party Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be +disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +2019 +Proxy Statement | Matador Resources Company 81 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/filing.txt b/raw/filings/0001520006/2018/0001520006-19-000048/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..f8dcafa5769903e2107672649ce649de3489d87d --- /dev/null +++ b/raw/filings/0001520006/2018/0001520006-19-000048/filing.txt @@ -0,0 +1,7847 @@ +10-K +1 +a20181231mtdr10-k.htm +10-K +Document +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2018 +or +¨ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission file number 001-34574 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas +27-4662601 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 +Dallas, Texas 75240 +75240 +(Address of principal executive offices) +(Zip Code) +Registrant’s telephone number, including area code: (972) 371-5200 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ý No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +ý +Accelerated filer +¨ +Non-accelerated filer +¨ +Smaller reporting company +¨ +Emerging growth company +¨ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ¨ No ý +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $3,305,546,848 . +As of February 26, 2019 , there were 116,388,317 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2019 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +31 +I TEM 1B. +Unresolved Staff Comments +56 +I TEM 2. +Properties +56 +I TEM 3. +Legal Proceedings +56 +I TEM 4. +Mine Safety Disclosures +56 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +57 +I TEM 6. +Selected Financial Data +60 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +62 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +83 +I TEM 8. +Financial Statements and Supplementary Data +85 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +85 +I TEM 9A. +Controls and Procedures +85 +I TEM 9B. +Other Information +88 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +88 +I TEM 11. +Executive Compensation +88 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +88 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +88 +I TEM 14. +Principal Accounting Fees and Services +88 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +89 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions, changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids, the success of our drilling program, the timing of planned capital expenditures, the sufficiency of our cash flow from operations together with available borrowing capacity under our credit facilities, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• +our business strategy; +• +our estimated future reserves and the present value thereof; +• +our cash flows and liquidity; +• +our financial strategy, budget, projections and operating results; +• +our oil and natural gas realized prices; +• +the timing and amount of future production of oil and natural gas; +• +the availability of drilling and production equipment; +• +the availability of oil field labor; +• +the amount, nature and timing of capital expenditures, including future exploration and development costs; +• +the availability and terms of capital; +• +our drilling of wells; +• +our ability to negotiate and consummate acquisition and divestiture opportunities; +• +government regulation and taxation of the oil and natural gas industry; +• +our marketing of oil and natural gas; +• +our exploitation projects or property acquisitions; +• +the integration of acquisitions with our business; +• +our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the operation and expansion of our Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; +• +the ability of our midstream joint venture to attract third-party volumes; +• +our costs of exploiting and developing our properties and conducting other operations; +• +general economic conditions; +• +competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• +the effectiveness of our risk management and hedging activities; +• +our technology; +• +environmental liabilities; +• +counterparty credit risk; +• +developments in oil-producing and natural gas-producing countries; +• +our future operating results; and +• +our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +1 +Table of Contents +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2018 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also continued to increase our leasehold and minerals position in the Delaware Basin, in particular through the BLM Acquisition (as defined below). In addition, we concluded several important financing transactions in 2018 , including the May 2018 public +2 +Table of Contents +offering of 7,000,000 shares of our common stock, the refinancing and issuance of senior unsecured notes and two increases in the borrowing base under our Credit Agreement (as defined below). San Mateo also achieved several important milestones in 2018, including the completion and successful start-up of the expansion of the Black River Processing Plant (as defined below), the formation of a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains All American Pipeline, L.P. (“Plains”) to gather and transport crude oil for us and third-party customers in and around the Rustler Breaks asset area, the completion and start-up of the Rustler Breaks Oil Pipeline System (as defined below), the addition of several significant third-party customers for salt water gathering and disposal and natural gas gathering and processing and the closing of the San Mateo Credit Facility (as defined below). These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2018 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2018 , we achieved record oil, natural gas and average daily oil equivalent production. In 2018 , we produced 11.1 million Bbl of oil, an increase of 42% , as compared to 7.9 million Bbl of oil produced in 2017 . We also produced 47.3 Bcf of natural gas, an increase of 24% from 38.2 Bcf of natural gas produced in 2017 . Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, an increase of 34% , as compared to 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, for the year ended December 31, 2017 . The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2018 , which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Oil production comprised 59% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2018 , as compared to 55% for the year ended December 31, 2017 . +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2018 , our estimated total proved oil and natural gas reserves were 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, an increase of 41% from 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, at December 31, 2017 . The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 79% and 93% to $2.25 billion and $2.58 billion , respectively, at December 31, 2018 , from $1.26 billion and $1.33 billion , respectively, at December 31, 2017 , primarily as a result of our ongoing delineation and development drilling activities in the Delaware Basin during 2018 and higher weighted average oil and natural gas prices used to estimate proved reserves. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 42% to 123.4 million Bbl at December 31, 2018 from 86.7 million Bbl at December 31, 2017 . Our proved natural gas reserves increased 39% to 551.5 Bcf at December 31, 2018 from 396.2 Bcf at December 31, 2017 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2018 . +At December 31, 2018 , proved developed reserves included 53.2 million Bbl of oil and 246.2 Bcf of natural gas, and proved undeveloped reserves included 70.2 million Bbl of oil and 305.2 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 44% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2018 . Proved developed reserves and proved oil reserves comprised 45% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2017 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past five years. We expect the Delaware Basin will continue to be our primary area of focus in 2019 . +3 +Table of Contents +We completed and began producing oil and natural gas from 141 gross (73.8 net) wells in the Delaware Basin in 2018 , including 82 gross (66.8 net) operated and 59 gross (7.0 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2018 . As a result, at December 31, 2018 , our total acreage position in the Delaware Basin had increased to approximately 222,200 gross ( 132,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on our seven main asset areas—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 54% to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 , as compared to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 MMcf of natural gas per day ( 66% of total natural gas production), in 2017 . We expect our Delaware Basin production to increase in 2019 as we continue the delineation and development of these asset areas. +Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2018 included: +• +in our Rustler Breaks asset area, the results from the David Edelstein State Com 12&11-24S-27E RB #203H well, our first operated two-mile horizontal well, the performance of our Wolfcamp A-XY completions moving to the northwest region of the asset area, positive tests of the Second Bone Spring formation and the continued delineation and development of previously tested horizons; +• +in our Wolf asset area, the results from several wells with longer laterals (greater than one mile) drilled and completed in the Wolfcamp A-XY interval in the southern portion of the asset area; +• +in our Jackson Trust asset area, the continued development of the Wolfcamp A-Lower interval; +• +in our Arrowhead and Ranger asset areas, the results from our Second and Third Bone Spring completions, particularly in the SST and Stebbins acreage blocks in the Arrowhead asset area, and results from the recently completed Verna Rae Federal #204H well in the Ranger asset area, whose 24-hour initial potential (“IP”) test results and subsequent well performance demonstrate the potential prospectivity of the Wolfcamp formation moving north in the Delaware Basin; +• +in our Antelope Ridge asset area, the testing of six distinct intervals during 2018, including the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower; and +• +the significant progress made in our midstream operations, including (i) the completion and successful startup of the expansion of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”) to a designed inlet capacity of 260 MMcf of natural gas per day, (ii) the completion of a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP, (iii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas, (iv) the entrance into a strategic relationship with Plains to gather and transport crude oil in the Rustler Breaks asset area, (v) placing into service crude oil gathering and transportation systems in the Wolf and Rustler Breaks asset areas, (vi) entering into long-term agreements with significant producers in Eddy County, New Mexico relating to the gathering and disposal of one such producer’s salt water and the gathering and processing of another such producer’s natural gas production and (vii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks asset area, significantly increasing San Mateo’s salt water disposal capacity. +We also completed and began producing oil and natural gas from four gross (1.5 net) wells in the Eagle Ford shale in South Texas in 2018 , including one gross (1.0 net) operated and three gross (0.5 net) non-operated wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2018 , although we did participate in the drilling and completion of eight gross (0.2 net) non-operated Haynesville shale wells that began producing in 2018 . +Financing Arrangements +We concluded several important financing transactions in 2018 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• +the completion of a public offering of 7,000,000 shares of our common stock, whereby we received net proceeds of approximately $226.4 million; +• +a series of transactions whereby we (i) issued $1.05 billion aggregate principal amount of senior notes and received net proceeds of $1.04 billion, (ii) redeemed $575.0 million aggregate principal amount of senior notes, (iii) improved the coupon rate on our senior notes outstanding to 5.875% from 6.875% and (iv) extended the maturity date of our senior notes from 2023 to 2026; +4 +Table of Contents +• +the amendment of our third amended and restated credit agreement (the “Credit Agreement”) to, among other items, (i) increase the maximum facility amount to $1.5 billion, (ii) increase the borrowing base to $850.0 million, (iii) increase the elected borrowing commitment to $500.0 million, (iv) extend the maturity to October 31, 2023, (v) reduce borrowing rates by 0.25% per annum and (vi) set the maximum leverage ratio at 4.00 to 1.00; and +• +San Mateo’s entrance into a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and the cash distribution of $195.0 million, which was distributed 51% to us and 49% to our partner. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional information regarding these financing arrangements. +BLM Acquisition +On September 12, 2018, we announced the successful acquisition of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million, or a weighted average cost of approximately $46,000 per net acre, in the Bureau of Land Management (the “BLM”) New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”). The acquired leasehold acreage includes approximately 2,800 gross and net acres in the Stateline asset area on the Texas/New Mexico border, 4,800 gross and net acres in the Antelope Ridge asset area, 400 gross and net acres in the Arrowhead asset area and 400 gross and net acres in the Twin Lakes asset area. The leases for all tracts covering the BLM Acquisition were issued in the fourth quarter of 2018. +At February 26, 2019 , we were actively pursuing drilling permits on a number of these tracts, including the approximately 2,800 gross and net acres in the Stateline asset area and the approximately 1,200 gross and net acres in the western portion of the Antelope Ridge asset area. We expect to begin drilling operations on these Stateline and western Antelope Ridge properties as early as the fourth quarter of 2019 or the first quarter of 2020. +Midstream Highlights +On January 22, 2018, we announced a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains to gather and transport crude oil for upstream producers in and around the Rustler Breaks asset area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. San Mateo completed its expanded oil gathering system in the Wolf asset area in Loving County, Texas (the “Wolf Oil Pipeline System”) in May 2018, and, in December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following a successful open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. +In late March 2018, San Mateo completed the expansion of the Black River Processing Plant, adding an incremental designed inlet capacity of 200 MMcf of natural gas per day and bringing the total designed inlet capacity of the Black River Processing Plant to 260 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin, and with the expanded capacity, San Mateo can offer natural gas processing services to other producers as well. +In October 2018, a subsidiary of San Mateo entered into a long-term agreement with a producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including the Company, at December 31, 2018 , San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant. In addition, in June 2018, a subsidiary of San Mateo entered into a long-term agreement with another significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. +2019 Recent Developments +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. As part of this transaction, we dedicated to San Mateo II acreage in the Stebbins area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. In addition, Five Point has committed to pay $125 million of the first $150 million of capital expenditures incurred by San Mateo II to +5 +Table of Contents +develop facilities in the Stebbins area and the Stateline asset area. Five Point has also provided us the opportunity to earn deferred performance incentives of up to $150 million over the next five years as we execute our operational plans in and around the Stebbins area and the Stateline asset area, plus additional performance incentives for securing volumes from third-party customers. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During 2018 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our asset areas by exploring for and developing more conventional targets as well, although for the year ended December 31, 2018 , essentially all of our efforts were focused on unconventional plays. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2018 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +222,200 +132,000 +630 +290.7 +5,442 +2,472.2 +191,490 +42.3 +45,237 +South Texas: +Eagle Ford (5) +32,000 +28,900 +148 +122.5 +238 +206.9 +12,189 +61.5 +3,158 +Northwest Louisiana/East Texas: +Haynesville +19,600 +12,000 +227 +20.4 +395 +100.2 +10,919 +46.5 +3,417 +Cotton Valley (6) +21,100 +18,600 +79 +53.3 +71 +49.2 +715 +100.0 +316 +Area Total (7) +25,500 +22,800 +306 +73.7 +466 +149.4 +11,634 +49.8 +3,733 +Total +279,700 +183,700 +1,084 +486.9 +6,146 +2,828.5 +215,313 +43.8 +52,128 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2018 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Each location represents a one-mile lateral. At December 31, 2018 , these engineered drilling locations included only 301 gross (147.6 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, in the Delaware Basin, 17 gross (17.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 14 gross (4.9 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2018 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2018 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2018 , we also were the operator for approximately 94% of our Eagle Ford acreage and approximately 64% of our Haynesville acreage, including +6 +Table of Contents +approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by an affiliate of Chesapeake Energy Corporation. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +As noted above in “— 2018 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2018 , and as a result, at December 31, 2018 , our total acreage position in Southeast New Mexico and West Texas was approximately 222,200 gross ( 132,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 34,200 gross (17,500 net) acres in our Ranger asset area in Lea County, 60,100 gross (25,700 net) acres in our Arrowhead asset area in Eddy County, 45,300 gross (26,200 net) acres in our Rustler Breaks asset area in Eddy County, 20,500 gross (17,300 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,700 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our recently acquired Stateline asset area in Eddy County and 44,300 gross (31,300 net) acres in our Twin Lakes asset area in Lea County at December 31, 2018 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2018 , our acreage position in the Delaware Basin was approximately 54% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical operated well and two horizontal operated wells, and the acreage acquired in the BLM Acquisition, which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 73% held by existing production at December 31, 2018 . +During the year ended December 31, 2018 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 141 gross (73.8 net) wells in the Delaware Basin, including 82 gross (66.8 net) operated wells and 59 gross (7.0 net) non-operated wells, throughout our various asset areas. At December 31, 2018 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, Avalon, the First Bone Spring, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2018 . Our average daily oil equivalent production from the Delaware Basin increased approximately 54% to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 , as compared to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 +7 +Table of Contents +MMcf of natural gas per day ( 66% of total natural gas production), in 2017 . Our average daily oil equivalent production from the Delaware Basin also grew approximately 41% from 34,859 BOE per day in the fourth quarter of 2017 to 49,309 BOE per day in the fourth quarter of 2018 . +At December 31, 2018 , approximately 89% of our estimated total proved oil and natural gas reserves, or 191.5 million BOE, was attributable to the Delaware Basin, including approximately 114.8 million Bbl of oil and 460.0 Bcf of natural gas, a 48% increase, as compared to 129.0 million BOE for the year ended December 31, 2017 . Our Delaware Basin proved reserves at December 31, 2018 comprised approximately 93% of our proved oil reserves and 83% of our proved natural gas reserves, as compared to approximately 89% of our proved oil reserves and 78% of our proved natural gas reserves at December 31, 2017 . +At December 31, 2018 , we had identified 5,442 gross ( 2,472.2 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 3,451 gross (2,278.0 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Each horizontal drilling location assumes a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2018 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing and that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible, at December 31, 2018 , the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2018 , these potential future drilling locations included 301 gross (147.6 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, to which we have assigned proved undeveloped reserves. +At December 31, 2018 , we were operating six drilling rigs in the Delaware Basin, and we expect to operate these six rigs in the Delaware Basin throughout 2019, including two rigs in each of the Rustler Breaks and Antelope Ridge asset areas, one rig in the Wolf/Jackson Trust asset areas and one rig in the Ranger/Arrowhead and Twin Lakes asset areas. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 12 months. The other three rigs are on short-term contracts with remaining obligations of six months or less. This affords us the ability to modify our drilling program as we may deem necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2019. +Rustler Breaks Asset Area - Eddy County, New Mexico +We operated two to three drilling rigs in our Rustler Breaks asset area during most of 2018. We completed and turned to sales 83 gross (41.8 net) horizontal wells and two gross (1.5 net) vertical wells in the Rustler Breaks asset area in 2018, including 46 gross (38.0 net) operated and 39 gross (5.3 net) non-operated wells. Most of these wells were completed in the Wolfcamp A-XY or Wolfcamp B-Blair intervals. +One of the key achievements of our drilling and completions program in our Rustler Breaks asset area in 2018 was our first operated two-mile horizontal well—the David Edelstein State Com 12&11-24S-27E RB #203H (Edelstein #203H) well, a Wolfcamp A-XY completion. The Edelstein #203H well tested 2,378 BOE per day (77% oil) during a 24-hour IP test in the third quarter of 2018. +We were pleased in 2018 with the success of our wells drilled in the northwestern portion of our acreage position. For example, the Miss Sue 12-23S-27E RB #201H (Miss Sue #201H) and the Michael Collins 11-23S-27E RB #201H (Michael Collins #201H) wells tested 1,706 BOE per day (76% oil) and 2,125 BOE per day (78% oil), respectively, during 24-hour IP tests. The Joe Coleman 13-23S-27E RB #201H and #203H (Joe Coleman #201H and #203H) wells tested 1,702 BOE per day (80% oil) and 1,831 BOE per day (73% oil), respectively, during 24-hour IP tests. In seven months of production, the Joe Coleman #201H and #203H wells have produced approximately 210,000 BOE (69% oil) and 190,000 BOE (70% oil), respectively. +In addition, the Garrett Fed Com #122H (Garrett #122H) well, a Second Bone Spring completion in the Rustler Breaks asset area, flowed 2,411 BOE per day (84% oil) during a 24-hour IP test. We expect to further delineate the Second Bone Spring formation moving to the northwest in our Rustler Breaks asset area using two-mile laterals beginning in the latter part of 2019 or early 2020. +8 +Table of Contents +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY and Wolfcamp A-Lower formations in 2018. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2018, and we completed and turned to sales 11 gross (8.0 net) operated horizontal wells in these asset areas. Most of these wells were completed in the Wolfcamp A-XY interval. +In the fourth quarter of 2018, we completed and placed on production the Wolf 80-TTT-B33 WF #206H and #208H (Wolf #206H and #208H) wells. These wells tested 2,509 BOE per day (41% oil) and 2,514 BOE per day (39% oil), respectively, during 24-hour IP tests. We attribute these well results to the selection of an improved landing target identified through the use of 3-D seismic data, the longer lateral lengths drilled and completed (5,600 and 6,200 feet, respectively) and an improved stimulation design. +Arrowhead and Ranger Asset Areas - Eddy and Lea Counties, New Mexico +We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2018. We completed and turned to sales 13 gross (7.9 net) horizontal wells in the Arrowhead and Ranger asset areas in 2018, including 10 gross (7.5 net) operated and three gross (0.4 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals. +The SST 6 State #123H and #124H wells, our first two Second Bone Spring wells drilled on the SST leasehold north of the Stebbins acreage in the Arrowhead asset area, tested 2,056 BOE per day (85% oil) and 1,845 BOE per day (86% oil), respectively, during 24-hour IP tests. The SST 6 State #123H well has produced approximately 240,000 BOE (70% oil) in its first eight months of production, and the SST 6 State #124H well has produced approximately 180,000 BOE (73% oil) in its first eight months of production. +In addition, we believe recent Wolfcamp wells drilled by Matador and other operators demonstrate the prospectivity of the Wolfcamp formation moving north in the Delaware Basin. We achieved positive Wolfcamp results in the Ranger asset area with the recent completion of the Verna Rae Federal Com #204H (Verna Rae #204H) well about three miles southwest of our Mallon wells. The Verna Rae #204H well flowed 1,586 BOE per day (90% oil) during a 24-hour IP test. +Antelope Ridge Asset Area - Lea County, New Mexico +We operated one to two drilling rigs in our Antelope Ridge asset area during 2018. We completed and turned to sales 29 gross (13.2 net) horizontal wells in this asset area in 2018, including 14 gross (12.3 net) operated and 15 gross (0.9 net) non-operated wells. As we began to delineate the Antelope Ridge asset area during 2018, we tested six different intervals, completing wells in the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower. +In particular, we were pleased with our delineation of the Wolfcamp A-Lower in the Antelope Ridge asset area. The Strong 14-24S-33E AR #214H (Strong #214H) well, our second Wolfcamp A-Lower test in the Antelope Ridge asset area, flowed 3,670 BOE per day (77% oil) during a 24-hour IP test. The Strong #214H well was a successful follow-up to our initial Wolfcamp A-Lower well in the Antelope Ridge asset area, the Leo Thorsness 13-24S-33E AR #211H (Leo Thorsness #211H) well, which flowed 2,906 BOE per day (72% oil) during a 24-hour IP test. The Strong #214H well has produced approximately 225,000 BOE (75% oil) in its first four months of production, and the Leo Thorsness #211H well has produced approximately 325,000 BOE (72% oil) in its first 11 months of production. +We also achieved several strong results in the Bone Spring in the Antelope Ridge asset area. The Irvin Wall State Com #131H (Irvin Wall #131H) well, our initial Third Bone Spring test in the Antelope Ridge asset area, flowed 2,343 BOE per day (81% oil) during a 24-hour IP test. The Irvin Wall #131H well has produced approximately 150,000 BOE (85% oil) in its first seven months of production. In addition, the Bill Alexander State Com #111H (Bill Alexander #111H) well, our second First Bone Spring test in the Antelope Ridge asset area, flowed 1,808 BOE per day (79% oil) during a 24-hour IP test. The Bill Alexander #111H well was a strong follow-up test of the First Bone Spring formation north of our initial First Bone Spring completion in the Antelope Ridge asset area, the Marlan Downey 9-23S-35E AR #111H well, which tested 1,491 BOE per day (82% oil) during a 24-hour IP test. The Bill Alexander #111H well has produced approximately 175,000 BOE (80% oil) in its first seven months of production. +9 +Table of Contents +Twin Lakes Asset Area - Lea County, New Mexico +In 2018, we performed our first test of the Wolfcamp D formation in the western portion of our Twin Lakes asset area in northern Lea County, New Mexico. This well, the Northeast Kemnitz #233H well, tested approximately 675 BOE per day (84% oil) on electric submersible pump during a 24-hour IP test. This well has exhibited a shallow production decline similar to th e D. Culbertson 26-15S-36E TL State #234H (D. Culbertson #234H) well, which was drilled and completed in 2017 and tested approximately 600 BOE per day (82% oil) during a 24-hour IP test. At December 31, 2018, we estimated an ultimate recovery of approximately 400,000 BOE from the D. Culbertson #234H well. Oil production from the D. Culbertson #234H well has been essentially flat, averaging approximately 110 Bbl of oil per day over the past 18 months, resulting in upward revisions to its estimated ultimate recovery. +Stateline Asset Area - Eddy County, New Mexico +In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net undeveloped leasehold acres prospective for multiple geologic targets. The acquired leases are federal leases and provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. As a result, we will retain an additional 17% of the net production from each well drilled and completed on these properties. The large majority of the acquired acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. The BLM has formally issued these leases, and we have begun actively pursuing drilling permits on these tracts. We expect to begin drilling operations on these properties in early 2020. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2018 , our properties included approximately 32,000 gross ( 28,900 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 93% of our Eagle Ford acreage was held by production at December 31, 2018 , and essentially all of our Eagle Ford acreage was either held by production at December 31, 2018 or not burdened by lease expirations before 2020 . +In early October 2018, we added one operated drilling rig to conduct a short-term drilling program in South Texas to drill up to 10 wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and to hold by production almost all of our remaining undeveloped Eagle Ford acreage. This rig operated in South Texas throughout the fourth quarter of 2018 and into early 2019. When drilling operations were finalized on the ninth well in early February 2019, this rig was released and was not moved to the Delaware Basin as we had previously anticipated. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight wells, including one well drilled in the Austin Chalk, are expected to be completed and turned to sales late in the first quarter or early in the second quarter of 2019. +Our average daily oil equivalent production from the Eagle Ford shale decreased 28% to 3,158 BOE per day, including 2,485 Bbl of oil per day and 4.0 MMcf of natural gas per day, during 2018 , as compared to 4,413 BOE per day, including 3,475 Bbl of oil per day and 5.6 MMcf of natural gas per day, during 2017 . For the year ended December 31, 2018 , 6% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 11% for the year ended December 31, 2017 . +At December 31, 2018 , approximately 6% of our estimated total proved oil and natural gas reserves, or 12.2 million BOE, was attributable to the Eagle Ford shale, including approximately 8.5 million Bbl of oil and 21.9 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 7% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2018 , as compared to approximately 11% of our proved oil reserves and 5% of our proved natural gas reserves at December 31, 2017 . +At December 31, 2018 , we had identified 238 gross ( 206.9 net) engineered locations for potential future drilling on our Eagle Ford acreage. Each drilling location assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into +10 +Table of Contents +account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2018 , these 238 gross ( 206.9 net) identified drilling locations included 17 gross (17.0 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2018 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though recent activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals. +Northwest Louisiana and East Texas — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2018 , although we did participate in the drilling and completion of eight gross (0.2 net) non-operated Haynesville shale wells that were turned to sales in 2018 . We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2019 . +At December 31, 2018 , we held approximately 25,500 gross ( 22,800 net) acres in Northwest Louisiana and East Texas, including 19,600 gross ( 12,000 net) acres in the Haynesville shale play and 21,100 gross ( 18,600 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the 13,200 gross ( 6,400 net) acres that we consider to be in the core area of the Haynesville shale play. +For the year ended December 31, 2018 , approximately 7% of our average daily oil equivalent production, or 3,733 BOE per day, including 12 Bbl of oil per day and 22.3 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 17% of our daily natural gas production during 2018 , as compared to approximately 29% of our daily natural gas production during 2017 . During the year ended December 31, 2017 , approximately 13% of our average daily oil equivalent production, or 5,060 BOE per day, including 12 Bbl of oil per day and 30.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2018 , approximately 16% of our daily natural gas production, or 20.5 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1% , or 1.8 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2017 , approximately 27% of our daily natural gas production, or 28.3 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 2% , or 2.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2018 , approximately 5% of our estimated total proved reserves, or 10.9 million BOE, was attributable to the Haynesville shale with another 0.3% of our proved reserves, or 0.7 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2018 , we had identified 395 gross ( 100.2 net) engineered locations for potential future drilling in the Haynesville shale play and 71 gross ( 49.2 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into account criteria such as +11 +Table of Contents +anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 395 gross ( 100.2 net) locations identified for future drilling on our Haynesville acreage, 321 gross (47.2 net) locations have been identified within the 13,200 gross ( 6,400 net) acres that we believe are located in the core area of the Haynesville shale play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2018 , these potential future drilling locations included 14 gross (4.9 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point. The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo. We earned $14.7 million in performance incentives effective January 31, 2018, which was paid by Five Point in the first quarter of 2018. Through January 31, 2019, we had earned an additional $14.7 million in performance incentives that we expect to be paid by Five Point in the first quarter of 2019 and may earn up to an additional $44.1 million in performance incentives over the next three years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo continues to provide firm capacity service to us at market rates, while also being a midstream service provider to other customers in and around our Wolf and Rustler Breaks asset areas. +In February 2019, we announced an expansion of our midstream business with the formation of San Mateo II. For additional information regarding this strategic joint venture, see “—2019 Recent Developments.” +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During 2017, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 60 MMcf of natural gas per day. As noted above in “—2018 Highlights—Midstream Highlights,” San Mateo completed this expansion of the Black River Processing Plant in late March 2018, bringing the total designed inlet capacity of the Black River Processing Plant to 260 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and production development activities in the Delaware Basin and offers processing opportunities for other producers’ development efforts. +As noted above in “—2018 Highlights—Midstream Highlights,” in October 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including us, at December 31, 2018 , San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant. +In addition, in early 2018, San Mateo completed an NGL pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and +12 +Table of Contents +fractionation costs and (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connected our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo in February 2017. +At December 31, 2018 , San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2018 , San Mateo gathered approximately 46.1 Bcf of natural gas, as compared to 32.1 Bcf of natural gas gathered during the year ended December 31, 2017 . In addition, during the year ended December 31, 2018 , San Mateo processed approximately 32.3 Bcf of natural gas, as compared to 18.4 Bcf of natural gas processed during the year ended December 31, 2017 . +Crude Oil Gathering and Transportation Assets +As noted above in “—2018 Highlights—Midstream Highlights,” subsidiaries of San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +Also, as noted above in “—2018 Highlights—Midstream Highlights,” San Mateo completed its expanded Wolf Oil Pipeline System in May 2018 and placed into service the Rustler Breaks Oil Pipeline System in December 2018. With the Wolf Oil Pipeline System and the Rustler Breaks Oil Pipeline System (collectively, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2018 , we estimated we had on pipe almost all of our oil production from the Wolf and Rustler Breaks asset areas, which comprised approximately 70% of our Delaware Basin oil production in the fourth quarter of 2018. With the San Mateo Oil Pipeline Systems in service, we expect to improve our oil price realizations in the Wolf and Rustler Breaks asset areas through the elimination of higher priced trucking services. +At December 31, 2018 , the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from origin points in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains Pipeline, L.P. and two trucking facilities. During the year ended December 31, 2018 , the San Mateo Oil Pipeline Systems had throughput of approximately 2.0 million Bbl of oil, as compared to 0.5 million Bbl of oil throughput during the year ended December 31, 2017 . +Produced Water Gathering and Disposal Assets +During 2018, San Mateo placed into service three commercial salt water disposal wells in the Rustler Breaks asset area and placed into service one additional commercial salt water disposal well there in February 2019, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to six at February 26, 2019 . In addition to its six commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, at February 26, 2019 , San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, and San Mateo’s salt water gathering systems included salt water gathering pipelines in the Rustler Breaks and Wolf asset areas. At February 26, 2019 , San Mateo had a designed disposal capacity of approximately 250,000 Bbl of salt water per day. +As noted above in “—2018 Highlights—Midstream Highlights,” in June 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. +During the year ended December 31, 2018 , San Mateo gathered approximately 44.0 million Bbl of salt water, as compared to 20.0 million Bbl of salt water gathered during the year ended December 31, 2017 . In addition, during the year ended December 31, 2018 , San Mateo disposed of approximately 47.5 million Bbl of salt water, as compared to 23.6 million Bbl of salt water disposed of during the year ended December 31, 2017 . +South Texas / Northwest Louisiana and East Texas +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases and from third parties and five non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo. +13 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2018, 2017 and 2016 . +Year Ended December 31, +2018 +2017 +2016 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +11,141 +7,851 +5,096 +Natural gas (Bcf) +47.3 +38.2 +30.5 +Total oil equivalent (MBOE) (1) +19,026 +14,212 +10,180 +Average daily production (BOE/d) (1) +52,128 +38,936 +27,813 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +57.04 +$ +49.28 +$ +41.19 +Oil, with realized derivatives (per Bbl) +$ +57.38 +$ +48.81 +$ +42.34 +Natural gas, without realized derivatives (per Mcf) +$ +3.49 +$ +3.72 +$ +2.66 +Natural gas, with realized derivatives (per Mcf) +$ +3.46 +$ +3.70 +$ +2.78 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +4.00 +$ +4.10 +$ +4.23 +Lease operating +$ +4.89 +$ +4.74 +$ +5.52 +Plant and other midstream services operating +$ +1.29 +$ +0.92 +$ +0.53 +Depletion, depreciation and amortization +$ +13.94 +$ +12.49 +$ +11.99 +General and administrative +$ +3.64 +$ +4.65 +$ +5.41 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +10,230 +907 +— +4 +11,141 +Natural gas (Bcf) +37.7 +1.5 +7.5 +0.6 +47.3 +Total oil equivalent (MBOE) (3) +16,512 +1,152 +1,247 +115 +19,026 +Percentage of total annual net production +86.8 +% +6.0 +% +6.6 +% +0.6 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +28,026 +2,485 +— +12 +30,523 +Natural gas (MMcf/d) +103.3 +4.0 +20.5 +1.8 +129.6 +Total oil equivalent (BOE/d) +45,237 +3,158 +3,417 +316 +52,128 +Average Sales Prices (4) +Oil (per Bbl) +$ +56.12 +$ +67.40 +$ +— +$ +64.72 +$ +57.04 +Natural gas (per Mcf) +$ +3.55 +$ +5.46 +$ +2.85 +$ +2.80 +$ +3.49 +Total oil equivalent (per BOE) +$ +42.88 +$ +60.02 +$ +17.09 +$ +18.59 +$ +42.08 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +4.79 +$ +17.25 +$ +5.41 +$ +19.11 +$ +5.68 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +14 +Table of Contents +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +6,579 +1,268 +— +4 +7,851 +Natural gas (Bcf) +25.1 +2.0 +10.3 +0.8 +38.2 +Total oil equivalent (MBOE) (3) +10,754 +1,611 +1,714 +133 +14,212 +Percentage of total annual net production +75.7 +% +11.3 +% +12.1 +% +0.9 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +18,023 +3,475 +— +12 +21,510 +Natural gas (MMcf/d) +68.6 +5.6 +28.3 +2.1 +104.6 +Total oil equivalent (BOE/d) +29,463 +4,413 +4,697 +363 +38,936 +Average Sales Prices (4) +Oil (per Bbl) +$ +49.08 +$ +50.29 +$ +— +$ +45.52 +$ +49.28 +Natural gas (per Mcf) +$ +4.03 +$ +4.69 +$ +2.83 +$ +2.79 +$ +3.72 +Total oil equivalent (per BOE) +$ +39.41 +$ +45.58 +$ +16.96 +$ +17.69 +$ +37.20 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.80 +$ +10.92 +$ +4.21 +$ +16.77 +$ +6.29 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +3,805 +1,286 +— +5 +5,096 +Natural gas (Bcf) +12.2 +3.1 +14.3 +0.9 +30.5 +Total oil equivalent (MBOE) (3) +5,834 +1,813 +2,385 +148 +10,180 +Percentage of total annual net production +57.3 +% +17.8 +% +23.4 +% +1.5 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +10,395 +3,517 +— +12 +13,924 +Natural gas (MMcf/d) +33.3 +8.6 +39.1 +2.3 +83.3 +Total oil equivalent (BOE/d) +15,941 +4,952 +6,517 +403 +27,813 +Average Sales Prices (4) +Oil (per Bbl) +$ +41.76 +$ +39.49 +$ +— +$ +38.78 +$ +41.19 +Natural gas (per Mcf) +$ +3.15 +$ +3.11 +$ +2.17 +$ +2.27 +$ +2.66 +Total oil equivalent (per BOE) +$ +33.81 +$ +33.46 +$ +13.04 +$ +14.39 +$ +28.60 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +7.32 +$ +12.74 +$ +4.73 +$ +17.07 +$ +7.82 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 increased 34% from our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, as compared to 38,936 BOE per day for the year ended December 31, 2017 . Our average daily oil production for the year ended December 31, 2018 was 30,524 Bbl of oil per day, an increase of 42% from 21,510 Bbl of oil per day for the year ended December 31, 2017 . Our average daily natural gas production for the year ended December 31, 2018 was 129.6 MMcf of natural gas per day, an increase of 24% from 104.6 MMcf of natural gas per day for the year ended December 31, 2017 . +Our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 increased 40% from our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, as compared to 27,813 BOE per day for the year ended December 31, 2016 . Our average daily oil production for the year ended December 31, 2017 was 21,510 Bbl of oil per day, an increase of 54% from 13,924 Bbl of oil per day for the year ended December 31, 2016 . Our average daily natural gas production for the year ended December 31, 2017 was 104.6 MMcf of natural gas per day, an increase of 25% from 83.3 MMcf of natural gas per day for the year ended December 31, 2016 . +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2018 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 77% in all wells that we operated at December 31, 2018 . For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 11%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +519 +241.0 +111 +49.7 +630 +290.7 +South Texas: +Eagle Ford (2) +144 +118.5 +4 +4.0 +148 +122.5 +Northwest Louisiana/East Texas: +Haynesville +— +— +227 +20.4 +227 +20.4 +Cotton Valley (3) +2 +2.0 +77 +51.3 +79 +53.3 +Area Total +2 +2.0 +304 +71.7 +306 +73.7 +Total +665 +361.5 +419 +125.4 +1,084 +486.9 +__________________ +(1) +Includes 224 gross (58.6 net) vertical wells that were acquired in multiple transactions. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2018, 2017 and 2016 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +17 +Table of Contents +At December 31, (1) +2018 +2017 +2016 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +123,401 +86,743 +56,977 +Natural Gas (Bcf) +551.5 +396.2 +292.6 +Total (MBOE) (3) +215,313 +152,771 +105,752 +Estimated proved developed reserves: +Oil (MBbl) +53,223 +36,966 +22,604 +Natural Gas (Bcf) +246.2 +190.1 +126.8 +Total (MBOE) (3) +94,261 +68,651 +43,731 +Percent developed +43.8 +% +44.9 +% +41.4 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +70,178 +49,777 +34,373 +Natural Gas (Bcf) +305.2 +206.1 +165.9 +Total (MBOE) (3) +121,052 +84,120 +62,021 +Standardized Measure (4) (in millions) +$ +2,250.6 +$ +1,258.6 +$ +575.0 +PV-10 (5) (in millions) +$ +2,579.3 +$ +1,333.4 +$ +581.5 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas, for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas, and for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2018, 2017 and 2016 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2018, 2017 and 2016 were, in millions, $328.7 , $74.8 and $6.5 , respectively. +Our estimated total proved oil and natural gas reserves increase d 41% from 152.8 million BOE at December 31, 2017 to 215.3 million BOE at December 31, 2018 . We added 69.6 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2018, approximately 3.7 times our 2018 annual production of 19.0 million BOE. Our proved oil reserves grew 42% from approximately 86.7 million Bbl at December 31, 2017 to approximately 123.4 million Bbl at December 31, 2018 . Our proved natural gas reserves increase d 39% from 396.2 Bcf at December 31, 2017 to 551.5 Bcf at December 31, 2018 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2018. We realized approximately 11.3 million BOE in net upward revisions to our proved reserves during 2018 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2017. Our proved reserves to production ratio at December 31, 2018 was 11.3 , an increase of 4% from 10.8 at December 31, 2017. +Over the past two years, our estimated total proved oil and natural gas reserves more than doubled, increasing 104% from 105.8 million BOE at December 31, 2016 to 215.3 million Bbl at December 31, 2018 . Our proved oil reserves grew 117% from 57.0 million Bbl at December 31, 2016 to 123.4 million Bbl at December 31, 2018 . Our proved developed oil reserves increased 135% from 22.6 million Bbl at December 31, 2016 to 53.2 million Bbl at December 31, 2018 . +18 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increase d 79% from $1.26 billion at December 31, 2017 to $2.25 billion at December 31, 2018 . The PV-10 of our total proved oil and natural gas reserves increase d 93% from $1.33 billion at December 31, 2017 to $2.58 billion at December 31, 2018 . The increases in our Standardized Measure and PV-10 are primarily a result of our delineation and development drilling activities in the Delaware Basin during 2018 and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2018 , as compared to December 31, 2017 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2018 were $62.04 per Bbl and $3.10 per MMBtu, an increase of 30% and 4% , respectively, as compared to average oil and natural gas prices of $47.79 per Bbl and $2.98 per MMBtu used to estimate proved reserves at December 31, 2017 . Our total proved reserves were made up of 57% oil and 43% natural gas at December 31, 2018 , as compared to 57% oil and 43% natural gas at December 31, 2017 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +Our proved developed oil and natural gas reserves increase d 37% from 68.7 million BOE at December 31, 2017 to 94.3 million BOE at December 31, 2018 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 44% from 37.0 million Bbl at December 31, 2017 to 53.2 million Bbl at December 31, 2018 . Our proved developed natural gas reserves increase d 30% from 190.1 Bcf at December 31, 2017 to 246.2 Bcf at December 31, 2018 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2018 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2017 +68,651 +Extensions and discoveries +14,666 +Purchases of minerals-in-place +596 +Revisions of prior estimates +3,091 +Production +(19,026 +) +Conversion of proved undeveloped to proved developed +26,283 +As of December 31, 2018 +94,261 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d 44% from 84.1 million BOE at December 31, 2017 to 121.1 million BOE at December 31, 2018 . Our proved undeveloped oil and natural gas reserves increased from 49.8 million Bbl and 206.1 Bcf, respectively, at December 31, 2017 to 70.2 million Bbl and 305.2 Bcf, respectively, at December 31, 2018 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2018 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2018 within five years of booking these reserves. +19 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2018 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2017 +84,120 +Extensions and discoveries +54,980 +Purchases of minerals-in-place +— +Revisions of prior estimates +8,235 +Conversion of proved undeveloped to proved developed +(26,283 +) +As of December 31, 2018 +121,052 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2015, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2015 +2,854 +23.4 +6,747 +104,989 +2016 +4,705 +13.1 +6,883 +94,579 +2017 +9,300 +45.0 +16,808 +211,860 +2018 +16,009 +61.7 +26,283 +$ +356,830 +Total +32,868 +143.2 +56,721 +$ +768,258 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2018 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +114,823 +460.0 +191,490 +$ +2,056.7 +$ +2,357.1 +South Texas: +Eagle Ford (5) +8,537 +21.9 +12,189 +160.9 +184.4 +Northwest Louisiana/East Texas: +Haynesville +— +65.5 +10,919 +31.0 +35.5 +Cotton Valley (6) +41 +4.1 +715 +2.0 +2.3 +Area Total +41 +69.6 +11,634 +33.0 +37.8 +Total +123,401 +551.5 +215,313 +$ +2,250.6 +$ +2,579.3 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2018 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2018 were approximately $ 328.7 million . +20 +Table of Contents +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Executive Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 41 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2018 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +123,000 +71,900 +99,200 +60,100 +222,200 +132,000 +South Texas: +Eagle Ford +29,900 +26,800 +2,100 +2,100 +32,000 +28,900 +Northwest Louisiana/East Texas (1) : +Haynesville +19,000 +11,500 +600 +500 +19,600 +12,000 +Cotton Valley +20,400 +18,500 +700 +100 +21,100 +18,600 +Area Total (2) +24,300 +22,200 +1,200 +600 +25,500 +22,800 +Total +177,200 +120,900 +102,500 +62,800 +279,700 +183,700 +__________________ +(1) +Developed acres include 2,800 gross and net mineral acres in Northwest Louisiana. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +21 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2018 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2024 and beyond totals 13,500 net acres, of which 8,800 net acres do not expire until 2028. +Acres +Acres +Acres +Acres +Acres +Expiring 2019 +Expiring 2020 +Expiring 2021 +Expiring 2022 +Expiring 2023 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +13,900 +9,400 +16,400 +8,900 +25,100 +14,900 +7,600 +8,200 +4,000 +5,400 +South Texas: +Eagle Ford +100 +100 +1,600 +1,500 +400 +400 +— +— +— +— +Northwest Louisiana/East Texas: +Haynesville +300 +300 +200 +200 +— +— +— +— +— +— +Cotton Valley +— +— +— +— +— +— +— +— +— +— +Area Total (2) +300 +300 +200 +200 +— +— +— +— +— +— +Total +14,300 +9,800 +18,200 +10,600 +25,500 +15,300 +7,600 +8,200 +4,000 +5,400 +__________________ +(1) +Approximately 49% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage through our 2019 drilling activities or by paying an additional lease bonus, where applicable. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2018 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2018, 2017 and 2016 . +Year Ended December 31, +2018 +2017 +2016 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +118 +54.7 +72 +43.7 +44 +23.5 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +35 +20.8 +33 +22.3 +28 +15.6 +Dry +— +— +— +— +— +— +Total Wells +Productive +153 +75.5 +105 +66.0 +72 +39.1 +Dry +— +— +— +— +— +— +22 +Table of Contents +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries (“OPEC”), weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, transportation capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the years ended December 31, 2018, 2017 and 2016 , we had four, four and three significant purchasers, respectively, that accounted for approximately 60% , 60% and 48% , respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. We intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +23 +Table of Contents +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and +24 +Table of Contents +limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believed, as of February 26, 2019 , that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System, which is subject to FERC jurisdiction, includes approximately 17 miles of 10-inch diameter crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC jurisdiction by any entity, to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to significantly increase the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”), went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The +25 +Table of Contents +Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors — We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In January 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would start at $0.60 per MMBtu in 2020 and escalate to $3.00 per MMBtu by 2024. If passed, such a surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors — Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor +26 +Table of Contents +all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”), and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the revision expands the scope of jurisdiction of the CWA, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. However, citing uncertainty caused by litigation surrounding the validity of this rule, in 2018 the EPA and the Corps announced a two-year stay of the application of the rule. Federal district court decisions have preserved the stay in Texas, New Mexico and Louisiana, and such jurisdictions remain subject to pre-2015 WOTUS regulations. As noted, litigation surrounding this rule is ongoing. On December 11, 2018, the EPA and the Corps released a proposal to revise the 2015 Clean Water Rule so as to narrow the regulatory definition of WOTUS, with a 60-day comment period to follow. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the +27 +Table of Contents +environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce, while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission (the “TRC”), adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to +28 +Table of Contents +the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In February 2019, a bill was introduced in the New Mexico Senate to place a moratorium on hydraulic fracturing that, if enacted, would last through June 1, 2023. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +Oil and natural gas exploration and production, operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act (the “ESA”), was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +29 +Table of Contents +A significant portion of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2018 , we had 264 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +30 +Table of Contents +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +Item 1A. Risk Factors. +Risks Related to the Oil and Natural Gas Industry and Our Business +Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. +The prices we receive for the oil and natural gas we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement, and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2018 , the average price of oil was $64.89 per Bbl, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $3.07 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2018, oil prices began the year at $60.42 per Bbl and reached a high of $76.41 per Bbl in early October. Throughout the fourth quarter of 2018, however, oil prices declined more than 40% from the high in early October to a low of $42.53 per Bbl in late December. Natural gas prices began 2018 at $2.95 per MMBtu and reached a high of $4.84 per MMBtu in mid-November before declining to $2.94 per MMBtu in late December. +Because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines caused us to recognize full-cost ceiling impairments in the first two quarters of 2016, and should prices decline again, we may recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules, and These Write-Downs Could Adversely Affect Our Financial Condition.” +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• +the domestic and foreign supply of, and demand for, oil and natural gas; +• +the actions of OPEC and state-controlled oil companies relating to oil price and production controls; +• +the prices and availability of competitors’ supplies of oil and natural gas; +• +the price and quantity of foreign imports; +• +the impact of U.S. dollar exchange rates; +• +domestic and foreign governmental regulations and taxes; +• +speculative trading of oil and natural gas futures contracts; +• +the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs; +• +the availability of refining capacity; +• +the prices and availability of alternative fuel sources; +• +weather conditions and natural disasters; +31 +Table of Contents +• +political conditions in or affecting oil and natural gas producing regions or countries, including the United States, Middle East, South America and Russia; +• +the continued threat of terrorism and the impact of military action and civil unrest; +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; +• +the level of global oil and natural gas inventories and exploration and production activity; +• +the impact of energy conservation efforts; +• +technological advances affecting energy consumption; and +• +overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil and natural gas prices do not necessarily fluctuate in direct relation to each other. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or to cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our estimated proved oil and natural gas reserves; +• +the amount of oil and natural gas we produce; +• +the prices at which we sell our production; +• +the costs of developing and producing our oil and natural gas reserves; +• +the costs of constructing, operating and maintaining our midstream facilities; +• +our ability to attract third-party customers for our midstream services; +• +our ability to acquire, locate and produce new reserves; +• +the ability and willingness of banks to lend to us; and +• +our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital +32 +Table of Contents +available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. +Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• +general economic and industry conditions, including the prices received for oil and natural gas; +• +shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• +potential drainage of oil and natural gas from our properties by adjacent operators; +• +the existence or magnitude of faults or unanticipated geological features; +• +loss of or damage to oilfield development and service tools; +• +accidents, equipment failures or mechanical problems; +• +title defects of the underlying properties; +• +increases in severance taxes; +• +adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• +domestic and foreign governmental regulations; and +• +proximity to and capacity of gathering, processing and transportation facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. For example, risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +33 +Table of Contents +• +landing our wellbore in the desired drilling zone; +• +staying in the desired drilling zone while drilling horizontally through the formation; +• +running our casing the entire length of the wellbore; +• +fracture stimulating the planned number of stages; +• +drilling out the plugs between stages following hydraulic fracturing operations; and +• +being able to run tools and other equipment consistently through the horizontal wellbore. +If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• +natural disasters; +• +adverse weather conditions; +• +loss of drilling fluid circulation; +• +blowouts where oil or natural gas flows uncontrolled at a wellhead; +• +cratering or collapse of the formation; +• +pipe or cement leaks, failures or casing collapses; +• +damage to pipelines, processing plants and disposal wells and associated facilities; +• +fires or explosions; +• +releases of hazardous substances or other waste materials that cause environmental damage; +• +pressures or irregularities in formations; and +• +equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in +34 +Table of Contents +Northwest Louisiana and East Texas. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 87% of our total oil and natural gas production for the year ended 2018 was attributable to our properties in the Delaware Basin. In 2016, 2017 and 2018, the vast majority of our capital expenditures were allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2019 will continue to be in the Delaware Basin, with the exception of amounts incurred in 2019 to conclude our South Texas drilling program and amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil, condensate and salt water trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +We May Not Be Able to Generate Sufficient Cash to Service All of Our Indebtedness and May Be Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May Not Be Successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +35 +Table of Contents +We May Incur Additional Indebtedness, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. +As of February 26, 2019 , the maximum facility amount under the Credit Agreement was $1.5 billion, the borrowing base was $850.0 million and our elected borrowing commitment was $500.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment. At February 26, 2019 , we had available borrowing capacity of approximately $406.3 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that is less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. +As of February 26, 2019 , the facility amount under the San Mateo Credit Facility was $250.0 million, and San Mateo had available borrowing capacity of approximately $13.8 million (after giving effect to outstanding letters of credit). The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $400.0 million. The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to fund acquisitions, develop our properties or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• +requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• +increasing our vulnerability to general adverse economic and industry conditions; +• +placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• +restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• +increasing the risk that we may default on our debt obligations. +The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination, and We Are Subject to Interest Rate Risk under Our Credit Agreement and the San Mateo Credit Facility. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 26, 2019 , our borrowing base was $850.0 million , our elected borrowing commitment was $500.0 million and we had $80.0 million in outstanding borrowings under, and approximately $13.7 million in outstanding letters of credit issued pursuant to, the Credit Agreement. As of February 26, 2019 , the maximum facility amount under the Credit Agreement was $1.5 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment. We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If we +36 +Table of Contents +borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount ranging from 0.25% to 1.25% per annum depending on the level of borrowings under the Credit Agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25% to 2.25% per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 0.50% to 1.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50% to 2.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions. +Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• +consolidate, merge or transfer all or substantially all of our assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. Low oil and natural gas prices or any decline in the prices of oil or natural gas may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. +Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is defined as consolidated total funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and +37 +Table of Contents +financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our Credit Rating May Be Downgraded, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations. +As of February 26, 2019 , our corporate credit rating from Standard & Poor’s Rating Services was “B+” and our corporate credit rating from Moody’s Investors Service was “B1.” We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +We Depend upon Several Significant Purchasers for the Sale of Most of Our Oil and Natural Gas Production. The Loss of One or More of These Purchasers Could, Among Other Factors, Limit Our Access to Suitable Markets for the Oil and Natural Gas We Produce. +We depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the years ended December 31, 2018, 2017 and 2016, we had four, four and three significant purchasers, respectively, that collectively accounted for approximately 60% , 60% and 48% , respectively, of our total oil, natural gas and NGL revenues. We cannot assure you that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. +The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the +38 +Table of Contents +extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +If Regulatory Changes Prevent Our Ability to Continue to Drill Wells in the Manner We Have Been, It Could Have a Material Adverse Impact on Our Future Production Results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +We Conduct a Portion of Our Operations through Joint Ventures, Which Subjects Us to Additional Risks That Could Have a Material Adverse Effect on the Success of These Operations, Our Financial Position, Results of Operations or Cash Flows. +We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for San Mateo and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows. +Our Midstream Operations Are Subject to Operational Risks, Which Could Result in Significant Damages and the Loss of Revenue. +San Mateo owns, and we operate, the Black River Processing Plant. There are significant risks associated with the operation of cryogenic natural gas processing plants. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in the Rustler Breaks asset area. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on +39 +Table of Contents +these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flow could be adversely affected. +Because of the Natural Decline in Production in the Regions of San Mateo’s Midstream Operations, San Mateo’s Long-Term Success Depends on its Ability to Obtain New Sources of Supplies, Which Depends on Certain Factors Beyond San Mateo’s Control. Any Decrease in Supplies to its Midstream Facilities Could Adversely Affect San Mateo’s Business and Operating Results. +San Mateo’s midstream facilities are or will be connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new supplies. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of third-party activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over third-party producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We Do Not Own All of the Land on Which Our Midstream Assets Are Located, Which Could Disrupt Our Operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Construction of Midstream Projects Subjects Us to Risks of Construction Delays, Cost Over-Runs, Limitations on Our Growth and Negative Effects on Our Financial Condition, Results of Operations, Cash Flows and Liquidity. +From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and water gathering systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of salt water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws That Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. +The operations of our midstream business, including San Mateo, and the operations of the third parties on whom we rely for gathering, processing and transportation services, are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. Substantial costs may be incurred in order to comply with existing laws and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new laws and regulations become applicable to operations, these changes may affect the costs that we pay for such services or the results of our midstream business, including San Mateo. Similarly, a failure to comply with such laws and regulations by us or the parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” +40 +Table of Contents +Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the judgment of the persons preparing the estimate; and +• +the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +actual costs and timing of development and production expenditures; +• +the amount and timing of actual production; and +• +changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles (“GAAP”), is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 56% of Our Total Proved Reserves at December 31, 2018 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. +At December 31, 2018 , approximately 56% of our total proved reserves were undeveloped and approximately 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +41 +Table of Contents +Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile become increasingly common in the Delaware Basin, we will have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. +At December 31, 2018 , we had leasehold interests in approximately 49,300 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2024 . Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic and geological data can be expensive to license or obtain and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +42 +Table of Contents +Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. +Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, Board of Directors and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +The Marketability of Our Production Is Dependent upon Oil, Natural Gas and NGL Gathering, Processing and Transportation Facilities, and the Unavailability of Satisfactory Oil, Natural Gas and NGL Gathering, Processing and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas, which would decrease the volumes sold from our wells, and, in certain circumstances, would require us to pay royalties on such flared natural gas. +The disruption of our or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments +43 +Table of Contents +under such agreements if we do not meet the gathering, disposal or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2019 . If we were required to shut in our production or flare our natural gas for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third-Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows. +Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +We Have Entered into Certain Long-Term Contracts That Require Us to Pay Fees to Our Service Providers Based on Minimum Volumes Regardless of Actual Volume Throughput and That May Limit Our Ability to Use Other Service Providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or salt water gathering or transportation agreements, natural gas processing agreements, salt water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2018 , our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $641.2 million over the terms of the agreements. In addition, in connection with the formation of San Mateo II, we entered into agreements with minimum volume commitments that totaled approximately $363.8 million. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +We Have Limited Control over Activities on Properties We Do Not Operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• +the timing and amount of capital expenditures; +• +the operator’s expertise and financial resources; +• +the rate of production of reserves, if any; +• +approval of other participants in drilling wells; and +• +selection and implementation or execution of technology. +44 +Table of Contents +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know about or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. +Before acquiring oil and natural gas properties, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +Our Ability to Complete Dispositions of Assets, or Interests in Assets, May Be Subject to Factors Beyond Our Control, and in Certain Cases We May Be Required to Retain Liabilities for Certain Matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or +45 +Table of Contents +indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. +If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the mineral interest owner or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. +It is not our practice in all acquisitions of oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules, and These Write-Downs Could Adversely Affect Our Financial Condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have: +• +downward adjustments to our estimated proved reserves; +• +increases in our estimates of development costs; or +• +deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established +46 +Table of Contents +by the call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. As of February 26, 2019 , we had approximately 50% and 15% of our estimated remaining 2019 oil and natural gas production, respectively, hedged. We currently have no hedges in place for NGLs, limited oil basis hedges in place for 2020 and otherwise no hedges in place beyond 2019 for oil or natural gas. +An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. For example, we sell much of our natural gas produced from the Delaware Basin at the Waha Hub. The price differential between the Waha Hub index and the Henry Hub index increased significantly through 2018 from approximately $0.50 per MMBtu at the beginning of the year to between $1.00 and $2.00 per MMBtu for most of 2018, but reaching highs of greater than $4.00 per MMBtu for a brief period at the end of the year. The natural gas price differential had narrowed to between $1.00 and $2.00 per MMBtu at the beginning of 2019, although it is possible that the differential could widen again at certain times during 2019. +Similarly, we sell much of our oil produced from the Delaware Basin at the Midland (Texas) Hub. The price differential between the West Texas Intermediate oil price and the oil price at the Midland Hub, also known as the Midland-Cushing (Oklahoma) differential, also increased significantly through 2018 from essentially no difference in the first quarter of 2018 to as much as $16.00 per Bbl in late September. The oil price differential had narrowed to about $5.00 per Bbl at the beginning of 2019, although it is possible that the differential could widen again at certain times during 2019. We have no derivative contracts in place to mitigate our exposure to these oil and natural gas price differentials during 2019 and have limited oil basis hedges in place for 2020. +We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. In addition to expenditures required in order for us to comply with such laws and regulations, these expenditures could also include payments for: +• +personal injuries; +• +property damage; +• +containment and clean-up of oil and other spills; +• +management and disposal of hazardous materials; +• +remediation, clean-up costs and natural resource damages; and +• +other environmental damages. +47 +Table of Contents +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or facilities are located, or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have an adverse impact on our ability to develop and produce our reserves. +We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The Tax Cuts and Jobs Act did not include any of these proposals, except for the repeal of the domestic manufacturing tax deduction for oil and natural gas companies. However, it is possible that such provisions could be proposed in the future. The passage of any legislation or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +In January 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would start at $0.60 per MMBtu in 2020 and escalate to $3.00 per MMBtu by 2024. If passed, such a surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. +48 +Table of Contents +Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods. +The Tax Cuts and Jobs Act includes provisions that generally (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our business interest income) for the year, (ii) permit us to offset only 80% (rather than 100%) of our taxable income with net operating losses we generate and (iii) limit our ability to deduct certain elements of executive compensation. Interest expense and net operating losses subject to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the Tax Cuts and Jobs Act repealed the domestic manufacturing tax deduction for oil and natural gas companies. These tax law changes could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might not have incurred otherwise, in the absence of these tax law changes. +Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands in March 2015. These rules were rescinded by rule in December 2017; however, in January 2018, California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the rules. This litigation is ongoing and future implementation of the BLM rules is uncertain at this time. +In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. In February 2019, a bill was introduced in the New Mexico Senate to place a moratorium on hydraulic fracturing that, if enacted, would last through June 1, 2023. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The Potential Adoption of Federal, State and Local Legislation and Regulations Intended to Address Potential Induced Seismicity in the Areas in Which We Operate Could Restrict Our Drilling and Production Activities, as well as Our Ability to Dispose of Produced Water Gathered from Such Activities, Which Could Decrease San Mateo’s Revenues and Result in Increased Costs and Additional Operating Restrictions or Delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and natural gas waste disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas, have modified their regulations or guidance to mitigate potential causes of induced seismicity. +49 +Table of Contents +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. We and San Mateo dispose of large volumes of produced water gathered from our or third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could decrease San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce, while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. In June 2017, the Trump administration announced its intention for the United States to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest date the United States can withdraw is November 2020. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and natural gas industry. However, in June 2017, the EPA proposed a two-year stay of certain requirements under this rule and in September 2018 proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements, which are expected to “significantly reduce” the rule’s regulatory burden. Any future international agreements, federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs, adversely affecting our profits, and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the +50 +Table of Contents +cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes. +New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. If regions reclassified as non-attainment areas under the lower ozone standard begin implementing new, more stringent regulations, those regulations could also apply to our or our customers’ operations. Generally, it will take the states several years to develop compliance plans for their non-attainment areas. The EPA’s final rule has been judicially challenged by both industry and other interested parties, and the outcome of this litigation may also impact implementation and revisions to the rule. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. The BLM then finalized a revised rule in 2018 which scaled back the waste-prevention requirements of the 2016 rule. Environmental groups have sued in federal district court to challenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. If not withdrawn or significantly revised, these rules are expected to result in an increase to our operating costs and changes in our operations. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations. +We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the TRC could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +51 +Table of Contents +A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. In December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System, which is subject to FERC jurisdiction and includes approximately 17 miles of 10-inch diameter crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The Rates of Our Regulated Assets are Subject to Review and Reporting by Federal Regulators, Which Could Adversely Affect Our Revenues. +The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates, and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. As of February 26, 2019 , the shippers on the Rustler Breaks Oil Pipeline System have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective agreements; however, other current or future shippers may still challenge our tariff rates. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.2 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new +52 +Table of Contents +rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. During the last quarter of 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +53 +Table of Contents +A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or Financial Loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our supervisory control and data acquisition (SCADA) systems, control important processes and facilities that are critical to our operations. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. +While we have not experienced any material losses due to cyber incidents, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Risks Relating to Our Common Stock +The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2018 , our stock price fluctuated between a high of $35.22 and a low of $13.97 . In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• +our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• +quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• +changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• +speculation in the press or investment community; +• +announcement or consummation of acquisitions, dispositions or joint ventures by us; +• +public reaction to our operations or plans, press releases, announcements and filings with the SEC; +• +sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• +general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• +the realization of any of the risk factors presented in this Annual Report; +• +the recruitment or departure of key personnel; +• +commencement of, involvement in or unfavorable resolution of litigation; +• +the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• +changes in market valuations of companies similar to ours; and +• +domestic and international economic, legal and regulatory factors unrelated to our performance. +54 +Table of Contents +If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. +We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. +Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• +authorization for our Board of Directors to issue preferred stock without shareholder approval; +• +a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• +the prohibition of cumulative voting in the election of directors; and +• +a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +55 +Table of Contents +Our Directors and Executive Officers Own a Significant Percentage of Our Equity, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. +As of February 26, 2019 , our directors and executive officers beneficially owned approximately 7% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 13 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several lawsuits encountered in the ordinary course of our business. While the ultimate outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on our financial condition, results of operations or cash flows. +Item 4. Mine Safety Disclosures. +Not applicable. +56 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 26, 2019 , we had 116,388,317 shares of common stock outstanding held by approximately 360 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2018 . +Equity Compensation Plan Information +Plan Category +Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights +Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights +Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1) (2) +2,962,249 +$ +23.48 +991,281 +Equity compensation plans not approved by security holders +— +— +— +Total +2,962,249 +$ +23.48 +991,281 +__________________ +(1) +Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. +(2) +The Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015 and approved by our shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8 to the consolidated financial statements in this Annual Report. +57 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2013 through December 31, 2018 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +58 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2018 , the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs +Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2018 to October 31, 2018 +11,777 +$ +33.39 +— +— +November 1, 2018 to November 30, 2018 +216 +25.79 +— +— +December 1, 2018 to December 31, 2018 +106 +15.49 +— +— +Total +12,099 +$ +33.10 +— +— +_________________ +(1) +The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +59 +Table of Contents +Item 6. Selected Financial Data. +The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2018 and selected consolidated balance sheet and cash flow data at December 31, 2018 , 2017 , 2016 , 2015 and 2014 . You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report. The financial information included in this Annual Report may not be indicative of our future results of operations, financial condition or cash flows. +Year Ended December 31, +2018 +2017 +2016 +2015 +2014 +(In thousands, except per share data) +Statement of operations data: +Revenues +Oil and natural gas revenues +$ +800,700 +$ +528,684 +$ +291,156 +$ +278,340 +$ +367,712 +Third-party midstream services revenues +21,920 +10,198 +5,218 +1,864 +1,213 +Sales of purchased natural gas +7,071 +— +— +— +— +Lease bonus - mineral acreage +2,489 +— +— +— +— +Realized gain (loss) on derivatives +2,334 +(4,321 +) +9,286 +77,094 +5,022 +Unrealized gain (loss) on derivatives +65,085 +9,715 +(41,238 +) +(39,265 +) +58,302 +Total revenues +899,599 +544,276 +264,422 +318,033 +432,249 +Expenses +Production taxes, transportation and processing +76,138 +58,275 +43,046 +35,650 +33,172 +Lease operating +92,966 +67,313 +56,202 +54,704 +49,945 +Plant and other midstream services operating +24,609 +13,039 +5,389 +3,489 +1,408 +Purchased natural gas +6,635 +— +— +— +— +Depletion, depreciation and amortization +265,142 +177,502 +122,048 +178,847 +134,737 +Accretion of asset retirement obligations +1,530 +1,290 +1,182 +734 +504 +Full-cost ceiling impairment +— +— +158,633 +801,166 +— +General and administrative +69,308 +66,016 +55,089 +50,105 +32,152 +Total expenses +536,328 +383,435 +441,589 +1,124,695 +251,918 +Operating income (loss) +363,271 +160,841 +(177,167 +) +(806,662 +) +180,331 +Other income (expense) +Net (loss) gain on asset sales and inventory impairment +(196 +) +23 +107,277 +908 +— +Interest expense +(41,327 +) +(34,565 +) +(28,199 +) +(21,754 +) +(5,334 +) +Prepayment premium on extinguishment of debt +(31,226 +) +— +— +— +— +Other income (expense) +1,551 +3,551 +(4 +) +616 +132 +Total other (expense) income +(71,198 +) +(30,991 +) +79,074 +(20,230 +) +(5,202 +) +Net income (loss) +299,764 +138,007 +(97,057 +) +(679,524 +) +110,754 +Net (income) loss attributable to non-controlling interest in subsidiaries +(25,557 +) +(12,140 +) +(364 +) +(261 +) +17 +Net income (loss) attributable to Matador Resources Company shareholders +$ +274,207 +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +Earnings (loss) per common share +Basic +$ +2.41 +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +$ +1.58 +Diluted +$ +2.41 +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +$ +1.56 +At December 31, +2018 +2017 +2016 +2015 +2014 +(In thousands) +Balance sheet data: +Cash and cash equivalents +$ +64,545 +$ +96,505 +$ +212,884 +$ +16,732 +$ +8,407 +Restricted cash +$ +19,439 +$ +5,977 +$ +1,258 +$ +44,357 +$ +609 +Net property and equipment +$ +3,122,864 +$ +1,881,456 +$ +1,184,525 +$ +1,012,406 +$ +1,322,072 +Total assets +$ +3,455,518 +$ +2,145,690 +$ +1,464,665 +$ +1,140,861 +$ +1,434,490 +Current liabilities +$ +330,022 +$ +282,606 +$ +169,505 +$ +136,830 +$ +142,036 +Long-term liabilities +$ +1,345,839 +$ +605,538 +$ +603,715 +$ +515,072 +$ +425,913 +Total Matador Resources Company shareholders’ equity +$ +1,688,880 +$ +1,156,556 +$ +690,125 +$ +488,003 +$ +866,408 +60 +Table of Contents +Year Ended December 31, +2018 +2017 +2016 +2015 +2014 +(In thousands) +Other financial data: +Net cash provided by operating activities +$ +608,523 +$ +299,125 +$ +134,086 +$ +208,535 +$ +251,481 +Net cash used in investing activities +$ +(1,515,253 +) +$ +(819,284 +) +$ +(448,739 +) +$ +(381,406 +) +$ +(569,922 +) +Oil and natural gas properties capital expenditures +$ +(1,357,802 +) +$ +(699,445 +) +$ +(379,067 +) +$ +(432,715 +) +$ +(560,849 +) +Expenditures for midstream and other property and equipment +$ +(165,784 +) +$ +(120,816 +) +$ +(74,845 +) +$ +(64,499 +) +$ +(9,152 +) +Net cash provided by financing activities +$ +888,232 +$ +408,499 +$ +467,706 +$ +224,944 +$ +321,170 +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ +553,223 +$ +336,063 +$ +157,892 +$ +223,138 +$ +262,943 +__________________ +(1) +Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “ —Non-GAAP Financial Measures” below. +Non-GAAP Financial Measures +We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, prepayment premium on extinguishment of debt and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +61 +Table of Contents +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2018 +2017 +2016 +2015 +2014 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net income (loss) attributable to Matador Resources Company shareholders +$ +274,207 +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +$ +110,771 +Net income (loss) attributable to non-controlling interest in subsidiaries +25,557 +12,140 +364 +261 +(17 +) +Net income (loss) +299,764 +138,007 +(97,057 +) +(679,524 +) +110,754 +Interest expense +41,327 +34,565 +28,199 +21,754 +5,334 +Total income tax (benefit) provision +(7,691 +) +(8,157 +) +(1,036 +) +(147,368 +) +64,375 +Depletion, depreciation and amortization +265,142 +177,502 +122,048 +178,847 +134,737 +Accretion of asset retirement obligations +1,530 +1,290 +1,182 +734 +504 +Full-cost ceiling impairment +— +— +158,633 +801,166 +— +Unrealized (gain) loss on derivatives +(65,085 +) +(9,715 +) +41,238 +39,265 +(58,302 +) +Stock-based compensation expense +17,200 +16,654 +12,362 +9,450 +5,524 +Net loss (gain) on asset sales and inventory impairment +196 +(23 +) +(107,277 +) +(908 +) +— +Prepayment premium on extinguishment of debt +31,226 +— +— +— +— +Consolidated Adjusted EBITDA +583,609 +350,123 +158,292 +223,416 +262,926 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries +(30,386 +) +(14,060 +) +(400 +) +(278 +) +17 +Adjusted EBITDA attributable to Matador Resources Company shareholders +$ +553,223 +$ +336,063 +$ +157,892 +$ +223,138 +$ +262,943 +Year Ended December 31, +2018 +2017 +2016 +2015 +2014 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities +$ +608,523 +$ +299,125 +$ +134,086 +$ +208,535 +$ +251,481 +Net change in operating assets and liabilities +(64,429 +) +25,058 +(1,809 +) +(8,980 +) +5,978 +Interest expense, net of non-cash portion +39,970 +34,097 +27,051 +20,902 +5,334 +Current income tax (benefit) provision +(455 +) +(8,157 +) +(1,036 +) +2,959 +133 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries +(30,386 +) +(14,060 +) +(400 +) +(278 +) +17 +Adjusted EBITDA attributable to Matador Resources Company shareholders +$ +553,223 +$ +336,063 +$ +157,892 +$ +223,138 +$ +262,943 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement borrowing base and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +Overview +We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we +62 +Table of Contents +conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +2018 Operational Highlights +During the year ended December 31, 2018 , we completed and began producing oil and natural gas from 82 gross (66.8 net) operated and 59 gross (7.0 net) non-operated wells in the Delaware Basin and from one gross (1.0 net) operated and three gross (0.5 net) non-operated Eagle Ford shale wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2018 , although we did participate in the drilling and completion of eight gross (0.2 net) non-operated Haynesville shale wells that began producing in 2018 . +During 2018 , we continued our focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We began 2018 operating six drilling rigs in the Delaware Basin and continued to do so through December 31, 2018. In early October 2018, we added a seventh operated drilling rig to our drilling program on a short-term contract in South Texas to drill up to 10 wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and to hold by production almost all of our remaining undeveloped Eagle Ford acreage. This rig operated in South Texas throughout the fourth quarter of 2018 and into early 2019. When drilling operations were finalized on the ninth well in early February 2019, this rig was released and was not moved to the Delaware Basin as we had previously anticipated. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight wells, including one well drilled in the Austin Chalk, are expected to be completed and turned to sales late in the first quarter or early in the second quarter of 2019. +The vast majority of our 2018 capital expenditures was directed to (i) the delineation and development of our leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin and (iv) the acquisition of additional leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays. Our remaining capital expenditures were primarily directed to the beginning of our short-term drilling and completion program in South Texas and to our participation in several non-operated wells drilled and completed in the Eagle Ford and Haynesville shales throughout 2018. +In September 2018, we announced the BLM Acquisition, pursuant to which we acquired 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million, or a weighted average cost of approximately $46,000 per net acre. In addition to the BLM Acquisition, we also acquired 21,400 net leasehold and mineral acres in the Delaware Basin during 2018, and as a result, at December 31, 2018 , we held approximately 222,200 gross ( 132,000 net) acres in Southeast New Mexico and West Texas, primarily in the Delaware Basin, in Lea and Eddy Counties, New Mexico and Loving County, Texas. +Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, an increase of 34% as compared to 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, for the year ended December 31, 2017 . Our average daily oil production in 2018 of 30,524 Bbl of oil per day increased 42% , as compared to an average daily oil production of 21,510 Bbl of oil per day in 2017 . This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin. Our average daily natural gas production of 129.6 MMcf per day for the year ended December 31, 2018 increased 24% from 104.6 MMcf per day for the year ended December 31, 2017 . This increase in natural gas production was primarily attributable to increased natural gas production associated with our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 59% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2018 , as compared to 55% for the year ended December 31, 2017 . +For the year ended December 31, 2018 , our oil and natural gas revenues were $800.7 million , an increase of 51% from oil and natural gas revenues of $528.7 million for the year ended December 31, 2017 . Our oil revenues and natural gas revenues increased 64% and 16% to approximately $635.6 million and $165.1 million , respectively, as compared to $386.9 million and $141.8 million , respectively, for the year ended December 31, 2017 . The increase in oil and natural gas revenues resulted from (i) the increases in oil and natural gas production for the year ended December 31, 2018 as noted above and (ii) higher weighted average realized oil prices of $57.04 per Bbl in 2018 , as compared to $49.28 per Bbl in 2017 , offset by lower weighted average realized natural gas prices of $3.49 per Mcf in 2018, as compared to $3.72 per Mcf in 2017. +We reported net income attributable to Matador Resources Company shareholders of approximately $274.2 million , or $2.41 per diluted common share, on a GAAP basis for the year ended December 31, 2018 , as compared to net income of $125.9 million , or $1.23 per diluted common share, for the year ended December 31, 2017 . Adjusted EBITDA for the year ended +63 +Table of Contents +December 31, 2018 was $553.2 million , as compared to Adjusted EBITDA of $336.1 million reported for the year ended December 31, 2017 . Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +At December 31, 2018 , our estimated total proved oil and natural gas reserves were 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, with a Standardized Measure of $2.25 billion and a PV-10 of $2.58 billion . At December 31, 2017 , our estimated total proved oil and natural gas reserves were 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, with a Standardized Measure of $1.26 billion and a PV-10 of $1.33 billion . Our estimated total proved reserves of 215.3 million BOE at December 31, 2018 represented a 41% year-over-year increase, as compared to 152.8 million BOE at December 31, 2017 . Our estimated proved oil reserves of 123.4 million Bbl at December 31, 2018 increased 42% , as compared to 86.7 million Bbl at December 31, 2017 . Our proved oil and natural gas reserves in the Delaware Basin increased 48% to 191.5 million BOE at December 31, 2018 , as compared to 129.0 million BOE at December 31, 2017 , primarily as a result of our ongoing delineation and development operations in the Delaware Basin. At December 31, 2018 , approximately 89% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 48% to 114.8 million Bbl at December 31, 2018 , as compared to 77.5 million Bbl at December 31, 2017 . Proved oil reserves comprised 57% of our total proved reserves at December 31, 2018 , as compared to 57% at December 31, 2017 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” +Midstream Highlights +We made significant progress in our midstream operations during 2018, including, among other accomplishments, (i) the completion and successful startup of the expansion of the Black River Processing Plant to a designed inlet capacity of 260 MMcf of natural gas per day, (ii) the completion of an NGL pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP, (iii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas, (iv) the entrance into a strategic relationship with Plains to gather and transport crude oil in the Rustler Breaks asset area, (v) placing into service crude oil gathering and transportation systems in the Wolf and Rustler Breaks asset areas, (vi) entering into long-term agreements with significant producers in Eddy County, New Mexico relating to the gathering and disposal of one such producer’s salt water and the gathering and processing of another such producer’s natural gas production and (vii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks asset area, significantly increasing San Mateo’s salt water disposal capacity. +2019 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2019 . We plan to operate six contracted drilling rigs drilling primarily oil and natural gas wells in the Delaware Basin throughout most of 2019 . Our 2019 estimated capital expenditure budget consists of $640 to $680 million for drilling, completing and equipping wells (“D/C/E capital expenditures”) and $55 to $75 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo and San Mateo II’s estimated combined 2019 capital expenditures of $180 to $220 million and also accounts for portions of the $50 million capital carry that Five Point is expected to provide to us in conjunction with the formation of San Mateo II. Substantially all of our 2019 estimated capital expenditures will be allocated to (i) the further delineation and development of our leasehold position, (ii) the continued construction of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts incurred in 2019 to conclude our South Texas drilling program and amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2019 Delaware Basin drilling program is expected to focus on the continued development of the Rustler Breaks and Wolf asset areas and the further delineation and development of the Antelope Ridge, Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas as well as the federal leasehold acreage in the western portion of the Antelope Ridge asset area acquired in the BLM Acquisition. +As noted above, we were operating a seventh operated drilling rig at the beginning of 2019 to conduct the short-term drilling program in South Texas, primarily in the Eagle Ford shale. When we concluded this short-term program in February 2019, we released this drilling rig and did not move this rig to the Delaware Basin as we had previously anticipated. To further narrow any potential difference between our 2019 capital expenditures and operating cash flows, we may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position, as well as to consider monetizing other +64 +Table of Contents +assets, such as certain mineral, royalty and non-core midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during 2019 . These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2019 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2019 . +At December 31, 2018 , we had $64.5 million in cash (excluding restricted cash) and $457.0 million in undrawn borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit). As a result, we expect to fund our capital expenditures for 2019 through a combination of cash on hand, operating cash flows, performance incentives in connection with the formation of San Mateo that were earned in the first quarter of 2019, borrowings under our Credit Agreement (assuming availability under our borrowing base) and borrowings under the San Mateo Credit Facility. In addition, in 2019, we expect Five Point to provide a portion of the $50 million capital carry in connection with the formation of San Mateo II. We may also consider funding a portion of our 2019 capital expenditures through borrowings under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or leasehold interests, particularly in our non-core asset areas, the sale or joint venture of oil and natural gas mineral interests, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. The aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs of our midstream activities, other opportunities that may become available to us and our ability to obtain capital. +65 +Table of Contents +Revenues +Our revenues are derived primarily from the sale of oil, natural gas and NGL production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or NGL prices. +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2018 +2017 +2016 +Operating Data: +Revenues (in thousands): (1) +Oil +$ +635,554 +$ +386,865 +$ +209,908 +Natural gas +165,146 +141,819 +81,248 +Total oil and natural gas revenues +800,700 +528,684 +291,156 +Third-party midstream services revenues +21,920 +10,198 +5,218 +Sales of purchased natural gas +7,071 +— +— +Lease bonus - mineral acreage +2,489 +— +— +Realized gain (loss) on derivatives +2,334 +(4,321 +) +9,286 +Unrealized gain (loss) on derivatives +65,085 +9,715 +(41,238 +) +Total revenues +$ +899,599 +$ +544,276 +$ +264,422 +Net Production Volumes: (1) +Oil (MBbl) +11,141 +7,851 +5,096 +Natural gas (Bcf) +47.3 +38.2 +30.5 +Total oil equivalent (MBOE) (2) +19,026 +14,212 +10,180 +Average daily production (BOE/d) (2) +52,128 +38,936 +27,813 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +57.04 +$ +49.28 +$ +41.19 +Oil, with realized derivatives (per Bbl) +$ +57.38 +$ +48.81 +$ +42.34 +Natural gas, without realized derivatives (per Mcf) +$ +3.49 +$ +3.72 +$ +2.66 +Natural gas, with realized derivatives (per Mcf) +$ +3.46 +$ +3.70 +$ +2.78 +________________ +(1) +We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2018 as Compared to Year Ended December 31, 2017 +Oil and natural gas revenues . Our oil and natural gas revenues increase d $272.0 million , or 51% , to $800.7 million for the year ended December 31, 2018 , as compared to $528.7 million for the year ended December 31, 2017 . Our oil revenues increase d $248.7 million , or 64% , to $635.6 million for the year ended December 31, 2018 , as compared to $386.9 million for the year ended December 31, 2017 . The increase in oil revenues resulted from (i) the 42% increase in our oil production to 11.1 million Bbl of oil for the year ended December 31, 2018 , or about 30,524 Bbl of oil per day, as compared to 7.9 million Bbl of oil, or about 21,510 Bbl of oil per day, for the year ended December 31, 2017 , and (ii) a higher weighted average oil price realized for the year ended December 31, 2018 of $57.04 per Bbl, as compared to $49.28 per Bbl realized for the year ended December 31, 2017 . This increase d oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increase d by $23.3 million , or 16% , to $165.1 million for the year ended December 31, 2018 , as compared to $141.8 million for the year ended December 31, 2017 . The increase in natural gas revenues resulted from the 24% increase in our natural gas production to 47.3 Bcf for the year ended December 31, 2018 , as compared to 38.2 Bcf for the year ended December 31, 2017 , but was partially offset by a slightly lower weighted average natural gas price realized for the year ended December 31, 2018 of $3.49 per Mcf, as compared to $3.72 per Mcf realized for the year ended December 31, 2017 . The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. +Third-party midstream services revenues. Our third-party midstream services revenues increased $11.7 million , or 115% , to $21.9 million for the year ended December 31, 2018 , as compared to $10.2 million for the year ended December 31, 2017 . Third-party midstream services revenues are only those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to the significant increase in third-party salt water gathering and disposal revenues to approximately $10.5 million during the year ended December 31, 2018 , as compared to approximately $2.1 million for the year ended December 31, 2017 , resulting from an increase in salt water +66 +Table of Contents +gathering and disposal at our facilities in the Rustler Breaks and Wolf asset areas in 2018 . The remaining increase in our third-party midstream services revenues was primarily attributable to an increase in natural gas gathering and processing revenues to approximately $10.7 million for the year ended December 31, 2018 , as compared to $7.9 million for the year ended December 31, 2017 , resulting from an increase in natural gas processing at the Black River Processing Plant. An expansion of the Black River Processing Plant from a designed capacity of 60 MMcf per day to 260 MMcf per day was completed and placed into service in early 2018. +Sales of purchased natural gas. Our sales of purchased natural gas were $7.1 million for the year ended December 31, 2018 . We had no sales of purchased natural gas for the year ended December 31, 2017 . Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we may periodically enter into with third parties whereby we process the third party’s natural gas at the Black River Processing Plant and then purchase, and subsequently sell, the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statement of operations. +Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $2.5 million for the year ended December 31, 2018 . We had no lease bonus revenues in 2017. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests. +Realized gain (loss) on derivatives . Our realized net gain on derivatives was $2.3 million for the year ended December 31, 2018 , as compared to a net loss of approximately $4.3 million for the year ended December 31, 2017 . We realized a net gain of $29.5 million from our oil basis swap contracts for the year ended December 31, 2018 , resulting from oil basis prices that were lower than the swap prices on certain of our oil basis swap contracts. This net gain was significantly offset by net loss es of $25.7 million and $1.4 million from our oil and natural gas costless collar contracts, respectively, for the year ended December 31, 2018 , resulting from oil and natural gas prices that were above the short call/ceiling prices of certain of our oil and natural gas costless collar contracts. We realized a net loss of $3.7 million and $0.6 million from our oil and natural gas derivative contracts, respectively, for the year ended December 31, 2017 , resulting from oil and natural gas prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts. We realized an average gain on our oil derivatives of approximately $0.34 per Bbl of oil produced during the year ended December 31, 2018 , as compared to an average loss of $0.47 per Bbl of oil produced during the year ended December 31, 2017 . Our total oil volumes hedged for the year ended December 31, 2018 represented 49% of our total oil production, as compared to 59% of our total oil production for the year ended December 31, 2017 . We realized an average loss on our natural gas and NGL derivatives of approximately $0.03 per Mcf produced during the year ended December 31, 2018 , as compared to an average loss of approximately $0.02 per Mcf produced for the year ended December 31, 2017 . Our total natural gas volumes hedged for the year ended December 31, 2018 represented 36% of our total natural gas production, as compared to 63% of our total natural gas production for the year ended December 31, 2017 . +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $65.1 million for the year ended December 31, 2018 , as compared to an unrealized gain of $9.7 million for the year ended December 31, 2017 . During the year ended December 31, 2018 , the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts increase d from a net liability of approximately $15.2 million to a net asset of approximately $49.8 million , resulting in an unrealized gain on derivatives of approximately $65.1 million for the year ended December 31, 2018 . During the year ended December 31, 2017 , the aggregate net fair value of our open oil and natural gas derivative contracts increased from a net liability of approximately $25.0 million to a net liability of approximately $15.2 million , resulting in an unrealized gain on derivatives of approximately $9.7 million for the year ended December 31, 2017 . +Year Ended December 31, 2017 as Compared to Year Ended December 31, 2016 +Oil and natural gas revenues . Our oil and natural gas revenues increased $237.5 million, or 82%, to $528.7 million for the year ended December 31, 2017, as compared to $291.2 million for the year ended December 31, 2016. Our oil revenues increased $177.0 million, or 84%, to $386.9 million for the year ended December 31, 2017, as compared to $209.9 million for the year ended December 31, 2016. The increase in oil revenues resulted from (i) a higher weighted average oil price realized for the year ended December 31, 2017 of $49.28 per Bbl, as compared to $41.19 per Bbl realized for the year ended December 31, 2016, and (ii) the 54% increase in our oil production to 7.9 million Bbl of oil for the year ended December 31, 2017, or about 21,510 Bbl of oil per day, as compared to 5.1 million Bbl of oil, or about 13,924 Bbl of oil per day, for the year ended December 31, 2016. This increased oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, but also to production from the five operated wells we completed and turned to sales in the Eagle Ford shale late in the second quarter and early in the third quarter of 2017. Our natural gas revenues increased by $60.6 million, or 75%, to $141.8 million for the year ended December 31, 2017, as compared to $81.2 million for the year ended December 31, 2016. The increase in natural gas revenues resulted from (i) a higher weighted average natural gas price +67 +Table of Contents +realized for the year ended December 31, 2017 of $3.72 per Mcf, as compared to $2.66 per Mcf realized for the year ended December 31, 2016, and (ii) the 25% increase in our natural gas production to 38.2 Bcf for the year ended December 31, 2017, as compared to 30.5 Bcf for the year ended December 31, 2016. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. +Third-party midstream services revenues. Our third-party midstream services revenues increased $5.0 million, or 95%, to $10.2 million for the year ended December 31, 2017, as compared to $5.2 million for the year ended December 31, 2016. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to a significant increase in natural gas gathering and processing revenues to approximately $7.9 million for the year ended December 31, 2017, as compared to $3.6 million for the year ended December 31, 2016, due to (i) the Black River Processing Plant being placed into service in the second half of 2016 and operating for the full year in 2017 and (ii) increased natural gas production in our Rustler Breaks and Wolf asset areas. The remaining increase in our third-party midstream services revenues was primarily attributable to the increase in third-party salt water disposal revenues to approximately $2.1 million during the year ended December 31, 2017, as compared to approximately $1.6 million for the year ended December 31, 2016, primarily due to an increase in salt water gathering and disposal at our facilities in the Rustler Breaks and Wolf asset areas in 2017. +Realized (loss) gain on derivatives . Our realized net loss on derivatives was $4.3 million for the year ended December 31, 2017, as compared to a net gain of approximately $9.3 million for the year ended December 31, 2016. We realized net losses of $3.7 million and $0.6 million from our oil and natural gas costless collar contracts, respectively, for the year ended December 31, 2017, resulting from oil and natural gas prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts. We realized net gains of $5.9 million and $3.4 million from our oil and natural gas derivative contracts, respectively, for the year ended December 31, 2016, resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. We realized an average loss on our oil derivatives of approximately $0.47 per Bbl produced during the year ended December 31, 2017, as compared to an average gain of $1.15 per Bbl produced during the year ended December 31, 2016. Our total oil volumes hedged for the year ended December 31, 2017 represented 59% of our total oil production, as compared to 50% of our total oil production for the year ended December 31, 2016. We realized an average loss on our natural gas and NGL derivatives of approximately $0.02 per Mcf produced during the year ended December 31, 2017, as compared to an average gain of approximately $0.12 per Mcf produced for the year ended December 31, 2016. Our total natural gas volumes hedged for the year ended December 31, 2017 represented 63% of our total natural gas production, as compared to 44% of our total natural gas production for the year ended December 31, 2016. +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $9.7 million for the year ended December 31, 2017, as compared to an unrealized loss of $41.2 million for the year ended December 31, 2016. During the year ended December 31, 2017, the aggregate net fair value of our open oil and natural gas derivatives contracts increased from a net liability of approximately $25.0 million to a net liability of approximately $15.2 million, resulting in an unrealized gain on derivatives of approximately $9.7 million for the year ended December 31, 2017. During the year ended December 31, 2016, the aggregate net fair value of our open oil and natural gas derivative contracts decreased from a net asset of approximately $16.3 million to a net liability of approximately $25.0 million, resulting in an unrealized loss on derivatives of approximately $41.2 million for the year ended December 31, 2016. +68 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2018 +2017 +2016 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing +$ +76,138 +$ +58,275 +$ +43,046 +Lease operating +92,966 +67,313 +56,202 +Plant and other midstream services operating +24,609 +13,039 +5,389 +Purchased natural gas +6,635 +— +— +Depletion, depreciation and amortization +265,142 +177,502 +122,048 +Accretion of asset retirement obligations +1,530 +1,290 +1,182 +Full-cost ceiling impairment +— +— +158,633 +General and administrative +69,308 +66,016 +55,089 +Total expenses +536,328 +383,435 +441,589 +Operating income (loss) +363,271 +160,841 +(177,167 +) +Other income (expense): +Net (loss) gain on asset sales and inventory impairment +(196 +) +23 +107,277 +Interest expense +(41,327 +) +(34,565 +) +(28,199 +) +Prepayment premium on extinguishment of debt +(31,226 +) +— +— +Other income (expense) +1,551 +3,551 +(4 +) +Total other (expense) income +(71,198 +) +(30,991 +) +79,074 +Income (loss) before income taxes +292,073 +129,850 +(98,093 +) +Total income tax benefit +(7,691 +) +(8,157 +) +(1,036 +) +Net income attributable to non-controlling interest in subsidiaries +(25,557 +) +(12,140 +) +(364 +) +Net income (loss) attributable to Matador Resources Company shareholders +$ +274,207 +$ +125,867 +$ +(97,421 +) +Expenses per BOE: +Production taxes, transportation and processing +$ +4.00 +$ +4.10 +$ +4.23 +Lease operating +$ +4.89 +$ +4.74 +$ +5.52 +Plant and other midstream services operating +$ +1.29 +$ +0.92 +$ +0.53 +Depletion, depreciation and amortization +$ +13.94 +$ +12.49 +$ +11.99 +General and administrative +$ +3.64 +$ +4.65 +$ +5.41 +Year Ended December 31, 2018 as Compared to Year Ended December 31, 2017 +Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increase d by approximately $17.9 million , or 31% , to $76.1 million for the year ended December 31, 2018 , as compared to $58.3 million for the year ended December 31, 2017 . The increase in production taxes, transportation and processing expenses on an absolute basis was primarily attributable to the $25.0 million increase in our production taxes to $58.0 million for the year ended December 31, 2018 , as compared to $33.0 million for the year ended December 31, 2017 , resulting from the $272.0 million increase in oil and natural gas revenues for the year ended December 31, 2018 , as compared to the year ended December 31, 2017 . The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to $18.2 million for the year ended December 31, 2018 , as compared to $25.3 million for the year ended December 31, 2017 . On a unit-of-production basis, our production taxes, transportation and processing expenses decrease d to $4.00 per BOE for the year ended December 31, 2018 , as compared to $4.10 per BOE for the year ended December 31, 2017 , which was attributable to the 34% increase in total oil equivalent production between the respective periods. +Lease operating expenses. Our lease operating expenses increase d by $25.7 million , or 38% , to $93.0 million for the year ended December 31, 2018 , as compared to $67.3 million for the year ended December 31, 2017 . Our lease operating expenses on a unit-of-production basis increase d 3% to $4.89 per BOE for the year ended December 31, 2018 , as compared to $4.74 per BOE for the year ended December 31, 2017 . The increase in lease operating expenses for the year ended December 31, 2018 was primarily attributable to an increase in the costs of services and equipment related to the increased number of wells we operated during the year ended December 31, 2018 , as compared to the year ended December 31, 2017 , resulting from our increased delineation and development drilling activities in the Delaware Basin. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increase d by $11.6 million , or 89% , to $24.6 million for the year ended December 31, 2018 , as compared to $13.0 million for the year ended +69 +Table of Contents +December 31, 2017 . This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $13.1 million for the year ended December 31, 2018 , as compared to $6.8 million for the year ended December 31, 2017 , (ii) increased expenses associated with the Black River Processing Plant, where a significant expansion was completed and placed into service in the first quarter of 2018, of $7.6 million for the year ended December 31, 2018 , as compared to $4.6 million for the year ended December 31, 2017 , and (iii) increased expenses associated with our expanded pipeline operations in the Wolf and Rustler Breaks asset areas of $3.5 million for the year ended December 31, 2018 , as compared to $1.3 million for the year ended December 31, 2017 . +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d by $87.6 million , or 49% , to $265.1 million for the year ended December 31, 2018 , as compared to $177.5 million for the year ended December 31, 2017 . On a unit-of-production basis, our depletion, depreciation and amortization expenses increase d 12% to $13.94 per BOE for the year ended December 31, 2018 , as compared to $12.49 per BOE for the year ended December 31, 2017 . The increase in both our total and unit-of-production depletion, depreciation and amortization expenses was primarily attributable to (i) higher estimated future development costs associated with proved undeveloped oil and natural gas reserves at December 31, 2018 , which was partially offset by the increase in our total proved oil and natural gas reserves between the respective periods, and (ii) increased depreciation expenses associated with our expanded midstream assets of approximately $10.5 million for the year ended December 31, 2018 , as compared to $5.2 million for the year ended December 31, 2017 . +General and administrative. Our general and administrative expenses increase d $3.3 million , or 5% , to $69.3 million for the year ended December 31, 2018 , as compared to $66.0 million for the year ended December 31, 2017 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses of approximately $10.7 million associated with additional employees to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of our continued growth. This increase was partially offset by an increase of capitalized general and administrative expenses of $6.8 million for the year ended December 31, 2018 . Our general and administrative expenses decrease d 22% on a unit-of-production basis to $3.64 per BOE for the year ended December 31, 2018 , as compared to $4.65 per BOE for the year ended December 31, 2017 , primarily attributable to the 34% increase in total oil equivalent production between the respective periods. +Interest expense. For the year ended December 31, 2018 , we incurred total interest expense of approximately $50.2 million . We capitalized approximately $8.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2018 and expensed the remaining $41.3 million to operations. For the year ended December 31, 2017 , we incurred total interest expense of approximately $41.9 million . We capitalized $7.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2017 and expensed the remaining $34.6 million to operations. The increase in total interest expense for the year ended December 31, 2018 , as compared to the year ended December 31, 2017 , was primarily attributable to an increase in our average debt outstanding. In August and September 2018, we completed a tender offer and redemption of our $575.0 million aggregate principal amount of 6.875% senior notes due 2023 (the “2023 Notes”). In August 2018, we issued $750.0 million aggregate principal amount of 5.875% notes due 2026 (the “Original 2026 Notes”), and in October 2018, we issued an additional $300.0 million aggregate principal amount of 5.875% notes due 2026 (the “Additional 2026 Notes” and, together with the Original 2026 Notes, the “2026 Notes”), increasing our total senior notes outstanding to $1.05 billion at December 31, 2018 , as compared to $575.0 million at December 31, 2017 . +Prepayment premium on extinguishment of debt. For the year ended December 31, 2018 , we incurred a prepayment premium on extinguishment of debt of $31.2 million resulting from the tender offer to purchase for cash and subsequent redemption of all of our $575.0 million aggregate principal amount of 2023 Notes. +Total income tax (benefit) provision . We recorded a total income tax benefit of $7.7 million for the year ended December 31, 2018 . Total income tax expense for the year ended December 31, 2018 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to (i) the change of approximately $80.0 million in our federal valuation allowance for the year ended December 31, 2018 , including the reversal of the valuation allowance, as we now believe we will be able to use the federal net operating losses prior to expiration, (ii) the partial reversal of a state valuation allowance of approximately $2.9 million on our state deferred tax assets for the year ended December 31, 2018 , as we now believe we will be able to use the state net operating losses prior to expiration, and (iii) the impact of permanent differences between book and taxable income. Our deferred tax assets exceeded our deferred tax liabilities at December 31, 2017 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. We established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015, and we retained a full valuation allowance at December 31, 2017 , due to uncertainties regarding the future realization of our deferred tax assets. The current tax benefit of $8.2 million for the year ended December 31, 2017 was primarily the result of the Tax Cuts and Jobs Act, under which corporate alternative minimum taxes were repealed. +70 +Table of Contents +Year Ended December 31, 2017 as Compared to Year Ended December 31, 2016 +Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increase d by approximately $15.2 million , or 35% , to $58.3 million for the year ended December 31, 2017 , as compared to $43.0 million for the year ended December 31, 2016 . The increase in production taxes, transportation and processing expenses on an absolute basis was primarily attributable to the $16.4 million increase in our production taxes to $33.0 million for the year ended December 31, 2017 , as compared to $16.6 million for the year ended December 31, 2016 , primarily due to the $237.5 million increase in oil and natural gas revenues for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . In addition, the production tax rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production becomes attributable to New Mexico, we expect our production tax expenses to increase. The increased production taxes were partially offset by a decrease in transportation and processing expenses. Transportation and processing expenses decreased to $25.3 million for the year ended December 31, 2017 , as compared to transportation and processing expenses of $26.5 million for the year ended December 31, 2016 . This decrease of $1.2 million was primarily due to the start-up in late August 2016 of the Black River Processing Plant, which processes most of the natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico, and which was operational for the full year in 2017. On a unit-of-production basis, our production taxes, transportation and processing expenses decrease d to $4.10 per BOE for the year ended December 31, 2017 , as compared to $4.23 per BOE for the year ended December 31, 2016 , due not only to the decreased transportation and processing charges attributable to the start-up of the Black River Processing Plant, but also to the 40% increase in total oil equivalent production during the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . +Lease operating expenses. Our lease operating expenses increase d by $11.1 million , or 20% , to $67.3 million for the year ended December 31, 2017 , as compared to $56.2 million for the year ended December 31, 2016 . The increase in lease operating expenses on an absolute basis for the year ended December 31, 2017 was primarily attributable to an increase in the costs of services and equipment related to the increased number of wells we operated during the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , resulting from our increased delineation and development drilling activities in the Delaware Basin. Our lease operating expenses on a unit-of-production basis decrease d 14% to $4.74 per BOE for the year ended December 31, 2017 , as compared to $5.52 per BOE for the year ended December 31, 2016 . The decrease in lease operating expenses on a unit-of-production basis for the year ended December 31, 2017 was attributable to (i) increased efficiencies as more salt water was gathered by pipeline to San Mateo’s disposal facilities in the Delaware Basin, (ii) decreased workover expenses, (iii) decreased salt water disposal and chemical costs associated with our Eagle Ford operations and (iv) a 40% increase in total oil equivalent production in 2017 , as compared to 2016 . +Plant and other midstream services operating. Our plant and other midstream services operating expenses increase d by $7.7 million , or 142% , to $13.0 million for the year ended December 31, 2017 , as compared to $5.4 million for the year ended December 31, 2016 . This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $6.8 million for the year ended December 31, 2017 , as compared to $3.6 million for the year ended December 31, 2016 , and (ii) increased expenses associated with the Black River Processing Plant, which began operating in August 2016, of $4.6 million for the year ended December 31, 2017 , as compared to $0.7 million for the year ended December 31, 2016 . +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d by $55.5 million , or 45% , to $177.5 million for the year ended December 31, 2017 , as compared to $122.0 million for the year ended December 31, 2016 . On a unit-of-production basis, our depletion, depreciation and amortization expenses increase d 4% to $12.49 per BOE for the year ended December 31, 2017 , as compared to $11.99 per BOE for the year ended December 31, 2016 . The increase in both our total depletion, depreciation and amortization and unit-of-production depletion, depreciation and amortization expenses was primarily attributable to (i) increased depreciation expenses of approximately $5.2 million for the year ended December 31, 2017 , as compared to $2.7 million for the year ended December 31, 2016 , associated with our new midstream assets placed into service in 2017 and (ii) higher estimated future development costs associated with proved undeveloped oil and natural gas reserves at December 31, 2017 , both of which were offset by the increase in our total proved oil and natural gas reserves between the respective periods. +Full-cost ceiling impairment. We recorded no impairment charge to the net capitalized costs of our oil and natural gas properties for the year ended December 31, 2017 . We recorded an impairment charge of $158.6 million to the net capitalized costs of our oil and natural gas properties for the year ended December 31, 2016 . +General and administrative. Our general and administrative expenses increase d $10.9 million , or 20% , to $66.0 million for the year ended December 31, 2017 , as compared to $55.1 million for the year ended December 31, 2016 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses of approximately $10.4 million associated with additional employees joining the Company to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of the continued growth of the +71 +Table of Contents +Company and to the $4.3 million increase in non-cash stock-based compensation expense to $16.7 million for the year ended December 31, 2017 , as compared to $12.4 million for the year ended December 31, 2016 . The increase in our non-cash stock-based compensation was attributable to the increased expense related to the vesting of awards granted from 2013 through 2017 and the granting of new awards during 2017, as well as a change in the vesting schedule applicable to equity awards granted to our board of directors resulting in a $1.5 million one-time stock-based compensation expense. Our general and administrative expenses decrease d 14% on a unit-of-production basis to $4.65 per BOE for the year ended December 31, 2017 , as compared to $5.41 per BOE for the year ended December 31, 2016 , primarily due to the 40% increase in total oil equivalent production between the respective periods. +Net gain on asset sales and inventory impairment. We recorded a net gain of $23,000 on asset sales and inventory impairment for the year ended December 31, 2017 , as compared to a net gain of $107.3 million for the year ended December 31, 2016 related to the sale of our wholly-owned subsidiary that owned the Loving County Processing System. See Note 5 to the consolidated financial statements in this Annual Report for more information on this sale. +Interest expense. For the year ended December 31, 2017 , we incurred total interest expense of approximately $41.9 million . We capitalized approximately $7.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2017 and expensed the remaining $34.6 million to operations. For the year ended December 31, 2016 , we incurred total interest expense of approximately $31.9 million . We capitalized $3.7 million of our interest expense on certain qualifying projects for the year ended December 31, 2016 and expensed the remaining $28.2 million to operations. The increase in total interest expense for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , was primarily attributable to an increase in our average debt outstanding. In December 2016, we issued an additional $175.0 million of 2023 Notes, increasing our total senior notes outstanding to $575.0 million from $400.0 million . As a result, we incurred interest on the entire $575.0 million in senior notes outstanding during the year ended December 31, 2017 , as compared to the year ended December 31, 2016 , when the $575.0 million of senior notes were outstanding for only a portion of December 2016. +Total income tax (benefit) provision . Our deferred tax assets exceeded our deferred tax liabilities at December 31, 2017 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in prior periods. We established a valuation allowance against the deferred tax assets beginning in the third quarter of 2015, and we retained a full valuation allowance at December 31, 2017 due to uncertainties regarding the future realization of our deferred tax assets. The current tax benefit of $8.2 million for the year ended December 31, 2017 was primarily the result of the Tax Cuts and Jobs Act, under which corporate alternative minimum taxes were repealed. As a result, corporate alternative minimum tax carryforwards will be refunded. The total income tax expense for the years ended December 31, 2017 and 2016 differed from amounts computed by applying the U.S. federal statutory tax rate to the pre-tax income or loss, respectively, due primarily to recording a valuation allowance against the net deferred tax asset position as a result of the full-cost ceiling impairments recorded for the years ended December 31, 2016 and 2015. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2019 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditure requirements through 2019 through a combination of cash on hand, operating cash flows, performance incentives in connection with the formation of San Mateo that were earned in the first quarter of 2019, borrowings under our Credit Agreement (assuming availability under our borrowing base) and borrowings under the San Mateo Credit Facility. In addition, in 2019, we expect Five Point to provide a portion of the $50 million capital carry in connection with the formation of San Mateo II. We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or leasehold interests, particularly in our non-core asset areas, the sale or joint venture of oil and natural gas mineral interests, as well as potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows. +At December 31, 2018 , we had cash totaling approximately $64.5 million and restricted cash totaling approximately $19.4 million , most of which was associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +On May 17, 2018, we completed a public offering of 7,000,000 shares of our common stock, receiving net proceeds of approximately $226.4 million after deducting offering costs totaling approximately $0.2 million . The proceeds from this offering were used to acquire additional leasehold and mineral acres in the Delaware Basin, to fund certain midstream initiatives in the Delaware Basin and for general corporate purposes, including to fund a portion of our capital expenditures. +72 +Table of Contents +Pending such uses, we used a portion of the proceeds from the offering to repay the $45.0 million in borrowings then outstanding under our Credit Agreement. +As of December 31, 2017 , we had $575.0 million of outstanding 2023 Notes with a coupon rate of 6.875%. On August 21, 2018, we issued $750.0 million of Original 2026 Notes with a coupon rate of 5.875% in a private placement. The Original 2026 Notes were issued at par value, and we received net proceeds of approximately $740.0 million, after deducting the initial purchasers’ discounts and estimated offering expenses. In conjunction with the offering of the Original 2026 Notes (the “2026 Notes Offering”), in August and September 2018, respectively, we completed a tender offer and redemption of all of the 2023 Notes (the “2023 Notes Tender Offer and Redemption”). We used a portion of the net proceeds from the 2026 Notes Offering to fund the 2023 Notes Tender Offer and Redemption. +In September 2018, we announced the BLM Acquisition, pursuant to which we acquired 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million, or a weighted average cost of approximately $46,000 per net acre. We financed the BLM Acquisition using cash on hand and borrowings under the Credit Agreement. +On October 4, 2018, we issued $300.0 million of Additional 2026 Notes with a coupon rate of 5.875%. The Additional 2026 Notes were issued pursuant to, and are governed by, the same indenture governing the Original 2026 Notes. The Additional 2026 Notes were issued at 100.5% of par, plus accrued interest from August 21, 2018. We received net proceeds from this offering of approximately $297.3 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest from August 21, 2018 paid by the initial purchasers of the Additional 2026 Notes. The proceeds from this offering were used to repay a portion of the $325.0 million in outstanding borrowings under the Credit Agreement, which were incurred in connection with the BLM Acquisition. In December 2018, pursuant to a registered exchange offer, we exchanged substantially all of the 2026 Notes for a like principal amount of 5.875% senior notes due 2026 that have been registered under the Securities Act (the “Notes”). The terms of the Notes are substantially the same as the terms of the 2026 Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the 2026 Notes do not apply to the Notes. The Notes will mature September 15, 2026, and interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. +In October 2018, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves at June 30, 2018. In connection with such review, we amended the Credit Agreement to, among other items, increase the maximum facility amount to $1.5 billion, increase the borrowing base to $850.0 million, increase the elected borrowing commitment to $500.0 million, extend the maturity to October 31, 2023, reduce borrowing rates by 0.25% per annum and set the maximum leverage ratio at 4.00 to 1.00. This October 2018 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment. +In December 2018, San Mateo entered into the San Mateo Credit Facility, a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent and including all lenders in the Credit Agreement. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which could expand lender commitments to up to $400.0 million. The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including real property, and is non-recourse to Matador and its other subsidiaries. +At December 31, 2018 , we had (i) $1.05 billion of outstanding Notes, (ii) $40.0 million in borrowings outstanding under the Credit Agreement and (iii) approximately $3.0 million in outstanding letters of credit issued pursuant to the Credit Agreement, and San Mateo had $220.0 million in borrowings outstanding under the San Mateo Credit Facility. At February 26, 2019 , we had (x) $1.05 billion of outstanding Notes, (y) $80.0 million in borrowings outstanding under the Credit Agreement and (z) approximately $13.7 million in outstanding letters of credit issued pursuant to the Credit Agreement, and San Mateo had $220.0 million in borrowings outstanding and approximately $16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2019 . We plan to operate six contracted drilling rigs drilling primarily oil and natural gas wells in the Delaware Basin throughout most of 2019 . Our 2019 estimated capital expenditure budget consists of $640 to $680 million for D/C/E capital expenditures and $55 to $75 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo and San Mateo II’s estimated combined 2019 capital expenditures of $180 to $220 million and also accounts for portions of the $50 million capital carry that Five Point is expected to provide to us in conjunction with the formation of San Mateo II. Substantially all of our 2019 estimated capital expenditures will be allocated to the further delineation and development of our leasehold position, to the continued construction of midstream assets and to our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts incurred in 2019 to conclude our South Texas drilling program and amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2019 Delaware Basin drilling program is expected to focus on the continued development of the Rustler Breaks and Wolf asset areas and the +73 +Table of Contents +further delineation and development of the Antelope Ridge, Jackson Trust, Ranger/Arrowhead and Twin Lakes asset areas as well as the federal leasehold acreage in the western portion of the Antelope Ridge asset area acquired in the BLM Acquisition. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 12 months. The other three rigs are on short-term contracts with remaining obligations of six months or less. This affords us the ability to modify our drilling program as we may deem necessary based on changing commodity prices and other factors. +To further narrow any potential difference between our 2019 capital expenditures and operating cash flows, we may divest portions of our non-core assets, particularly in the Haynesville shale and in parts of our South Texas positions, as well as to consider monetizing other assets, such as certain mineral, royalty and non-core midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during 2019 . These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2019 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2019 . +Our 2019 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2019 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2019 and the hedges we currently have in place. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 11 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2018 . See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” +74 +Table of Contents +Our cash flows for the years ended December 31, 2018, 2017 and 2016 are presented below. +Year Ended December 31, +2018 +2017 +2016 +(In thousands) +Net cash provided by operating activities +$ +608,523 +$ +299,125 +$ +134,086 +Net cash used in investing activities +(1,515,253 +) +(819,284 +) +(448,739 +) +Net cash provided by financing activities +888,232 +408,499 +467,706 +Net change in cash +$ +(18,498 +) +$ +(111,660 +) +$ +153,053 +Cash Flows Provided by Operating Activities +Net cash provided by operating activities increased by $309.4 million to $608.5 million for the year ended December 31, 2018 , as compared to net cash provided by operating activities of $299.1 million for the year ended December 31, 2017 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $544.1 million for the year ended December 31, 2018 from $324.2 million for the year ended December 31, 2017 . This increase was primarily attributable to higher oil and natural gas production and higher oil prices realized during the year ended December 31, 2018 , as compared to the year ended December 31, 2017 . Changes in our operating assets and liabilities between December 31, 2017 and December 31, 2018 also resulted in a net increase of approximately $89.5 million in net cash provided by operating activities for the year ended December 31, 2018 , as compared to the year ended December 31, 2017 . +Net cash provided by operating activities increased by $165.0 million to $299.1 million for the year ended December 31, 2017 , as compared to net cash provided by operating activities of $134.1 million for the year ended December 31, 2016 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $324.2 million for the year ended December 31, 2017 from $132.3 million for the year ended December 31, 2016 . This increase was primarily attributable to higher oil and natural gas production and higher commodity prices realized during the year ended December 31, 2017, as compared to the year ended December 31, 2016. Changes in our operating assets and liabilities between December 31, 2016 and December 31, 2017 also resulted in a net decrease of approximately $26.9 million in net cash provided by operating activities for the year ended December 31, 2017 , as compared to the year ended December 31, 2016 . +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities increased by $696.0 million to $1.52 billion for the year ended December 31, 2018 from $819.3 million for the year ended December 31, 2017 . This increase in net cash used in investing activities was primarily attributable to (i) an increase of $658.4 million in oil and natural gas properties capital expenditures for the year ended December 31, 2018 , as compared to the year ended December 31, 2017 , and (ii) an increase of approximately $45.0 million in expenditures for midstream and other property and equipment, which included the construction and installation of an expansion of the Black River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline infrastructure. These increases were partially offset by an increase of $7.4 million in proceeds from the sale of other assets. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2018 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition of additional leasehold acreage and mineral interests in the Delaware Basin, including, in particular, the BLM Acquisition. +Net cash used in investing activities increased by $370.5 million to $819.3 million for the year ended December 31, 2017 from $448.7 million for the year ended December 31, 2016. This increase in net cash used in investing activities was primarily attributable to (i) an increase of $320.4 million in oil and natural gas properties capital expenditures for the year ended December 31, 2017, as compared to the year ended December 31, 2016, and (ii) an increase of approximately $46.0 million in expenditures for midstream and other property and equipment, which includes the construction and installation of an expansion of the Black River Processing Plant, additional salt water disposal wells and new pipeline infrastructure. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2017 was primarily attributable to our operated and +75 +Table of Contents +non-operated drilling and completion activities in the Delaware Basin, as well as the acquisition of additional leasehold acreage and mineral interests in the Delaware Basin. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $888.2 million for the year ended December 31, 2018 , as compared to net cash provided by financing activities of $408.5 million for the year ended December 31, 2017 . The net cash provided by financing activities for the year ended December 31, 2018 was primarily attributable to the total proceeds from the issuance of the Notes of $1.05 billion , borrowings under our Credit Agreement of $410.0 million , borrowings under the San Mateo Credit Facility of $220.0 million , proceeds from our May 2018 equity offering of $226.6 million , contributions from non-controlling interest owners of the less-than-wholly-owned subsidiaries of $85.8 million , contributions related to the formation of San Mateo of $14.7 million and proceeds from stock options exercised of $0.8 million . These cash inflows were partially offset by (i) costs related to the 2023 Notes Tender Offer and Redemption of $605.8 million , (ii) repayment of borrowings under our Credit Agreement of $370.0 million , (iii) distributions to non-controlling interest owners of the less-than-wholly-owned subsidiaries of $121.5 million , (iv) costs to issue equity and the 2026 Notes of $14.3 million , (v) costs to enter into or amend credit facilities of $3.1 million and (vi) $6.5 million in taxes paid related to net share settlement of stock-based compensation. +Net cash provided by financing activities was $408.5 million for the year ended December 31, 2017 , as compared to net cash provided by financing activities of $467.7 million for the year ended December 31, 2016 . The net cash provided by financing activities for the year ended December 31, 2017 was primarily attributable to the total proceeds from our October 2017 equity offering of $208.7 million, contributions related to the formation of San Mateo of $171.5 million and contributions from non-controlling interest owners of less-than-wholly subsidiaries of $44.1 million, offset by distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries of $10.0 million, $5.8 million in taxes paid related to net share settlement of stock-based compensation and the purchase of the non-controlling interest in a less-than-wholly-owned subsidiary of $2.7 million. +Net cash provided by financing activities was $467.7 million for the year ended December 31, 2016 , as compared to net cash provided by financing activities of $224.9 million for the year ended December 31, 2015. The net cash provided by financing activities for the year ended December 31, 2016 was primarily attributable to the total proceeds of the 2016 equity offerings of $288.5 million, the total proceeds of the December 2016 notes offering of $184.6 million and borrowings under our Credit Agreement of $120.0 million, offset by the costs of the 2016 equity offerings of $0.8 million, the costs of the December 2016 notes offering of $2.7 million, the repayment of $120.0 million in borrowings under our Credit Agreement in December 2016 and $1.9 million in taxes paid related to net share settlement of stock-based compensation. +See Note 6 to the consolidated financial statements in this Annual Report for a summary of our debt, including our Credit Agreement, the San Mateo Credit Facility and the senior notes. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2018 , the material off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) non-operated drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) firm transportation, gathering, processing and disposal commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 13 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +76 +Table of Contents +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2018 . +Payments Due by Period +Total +Less Than 1 Year +1-3 Years +3-5 Years +More Than 5 Years +(In thousands) +Contractual Obligations: +Revolving credit borrowings, including letters of credit (1) +$ +262,991 +$ +— +$ +— +$ +262,991 +$ +— +Senior unsecured notes (2) +1,050,000 +— +— +— +1,050,000 +Office leases +28,953 +3,091 +7,791 +8,150 +9,921 +Non-operated drilling commitments (3) +24,320 +24,320 +— +— +— +Drilling rig contracts (4) +28,381 +28,381 +— +— +— +Asset retirement obligations +31,086 +1,350 +914 +2,094 +26,728 +Natural gas transportation, gathering and processing agreements with non-affiliates (5) +420,149 +18,936 +85,944 +85,944 +229,325 +Gathering, processing and disposal agreements with San Mateo (6) +221,101 +800 +69,994 +75,102 +75,205 +Natural gas construction contracts (7) +3,635 +3,635 +— +— +— +Total contractual cash obligations +$ +2,070,616 +$ +80,513 +$ +164,643 +$ +434,281 +$ +1,391,179 +__________________ +(1) +At December 31, 2018 , we had $40.0 million of borrowings outstanding under the Credit Agreement and approximately $3.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2023. We also had $220.0 million of borrowings outstanding under the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. The amounts included in the table above represent principal maturities only. Assuming the amounts outstanding and interest rates of 3.68% and 4.01%, respectively, at December 31, 2018 , the interest expense is expected to be approximately $1.5 million and $8.8 million each year until maturity. +(2) +The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of December 31, 2018 is expected to be approximately $61.7 million each year until maturity. +(3) +At December 31, 2018 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2018 . If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $24.3 million at December 31, 2018 , which we expect to incur within the next year. +(4) +We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) +In late 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. In late 2017, we entered into an 18-year fixed-fee natural gas transportation agreement where we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline in Eddy County, New Mexico. In late 2017, we also entered into a fixed-fee NGL transportation and fractionation agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing Plant. We have committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed in 2020. We have no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then we do not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then we will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If we do not meet our NGL volume commitment in any quarter during the seven-year commitment period, we will be required to pay a deficiency fee per gallon of NGL deficiency. The amounts in the table assume that the seven-year period containing minimum NGL volume commitments begins in 2020. In the second quarter of 2018, we entered into a 16-year, fixed-fee natural gas transportation agreement that begins on October 1, 2019, whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Additionally, in the second quarter of 2018, we entered into a short-term natural gas transportation agreement whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Lastly, in the second quarter of 2018, we entered into a 10-year, fixed-fee natural gas sales agreement whereby we committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date for such pipeline, which is expected to be operational in late 2019. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(6) +In February 2017, we dedicated our current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(7) +During the first quarter of 2018, a subsidiary of San Mateo entered into agreements for additional field compression and an amine gas treatment unit to maximize the operation of the Black River Processing Plant. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +77 +Table of Contents +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. +In 2018, oil prices generally improved from the lower prices we experienced in 2016 and 2017, although oil prices in 2018 remained significantly below their most recent highs in 2014. For the year ended December 31, 2018, oil prices averaged $64.89 per Bbl, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. During 2018, oil prices began the year at $60.42 per Bbl and increased steadily, reaching a high of $76.41 per Bbl in early October. During the fourth quarter of 2018, however, oil prices declined more than 40% from the high in early October to a low of $42.53 per Bbl in late December. +We realized a weighted average oil price of $57.04 per Bbl ($57.38 per Bbl including realized gains for oil derivatives) for our oil production for the year ended December 31, 2018, as compared to $49.28 per Bbl ($48.81 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2017. At February 26, 2019 , the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date had improved from year-end 2018, closing at $55.50 per Bbl, and was lower compared to $63.91 per Bbl on February 26, 2018. +Natural gas prices traded in a fairly narrow range during much of 2018, before both rising and falling sharply during the fourth quarter of 2018. For the year ended December 31, 2018, natural gas prices averaged $3.07 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2018, natural gas prices began the year at $2.95 per MMBtu and reached a high of $4.84 per MMBtu in mid-November, before declining to $2.94 per MMBtu in late December. +We realized a weighted average natural gas price of $3.49 per Mcf ($3.46 per Mcf included realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2018, as compared to $3.72 per Mcf ($3.70 per Mcf including realized losses from natural gas and NGL derivatives) for the year ended December 31, 2017. At February 26, 2019 , the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had declined slightly from year-end 2018, closing at $2.86 per MMBtu, and was slightly higher as compared to $2.64 per MMBtu at February 26, 2018. +The prices we receive for oil, natural gas and NGLs heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically, and, as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. We are uncertain if oil and natural gas prices may rise from their current levels, and in fact, oil and natural gas prices may decrease in future periods. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. +In addition, the prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2018, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and most of our natural gas production from the Delaware Basin was sold based on prices established at the Waha Hub in far West Texas. During the second quarter of 2018, the price differentials for oil sold in Midland and natural gas sold at the Waha Hub compared to the benchmark prices for oil and natural gas, respectively, began to widen significantly and continued to widen throughout much of the year. These widening basis differentials negatively impacted our oil and natural gas revenues throughout the second, third and fourth quarters of 2018. +During 2018, the Midland-Cushing (Oklahoma) oil price differential increased substantially from essentially no difference in the first quarter to as much as $16.00 per Bbl in late September, although since then, it has improved. The Midland-Cushing (Oklahoma) oil price differential narrowed to about $5.00 per Bbl at the beginning of 2019 and is anticipated to narrow further +78 +Table of Contents +during 2019, although it is possible that this differential could widen again at certain times during 2019. Similarly, the natural gas price differential increased significantly throughout 2018 from about $0.50 per MMBtu at the beginning of the year to between $1.00 and $2.00 per MMBtu for most of 2018, but reaching highs of greater than $4.00 per MMBtu for a brief period near the end of the year. The natural gas price differential narrowed to between $1.00 and $2.00 per MMBtu at the beginning of 2019 and is anticipated to remain in this range for much of 2019, although it is possible that this differential could widen again at certain times during 2019. +We anticipate that these wider oil and natural gas price differentials could persist throughout much of 2019 or longer until additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is completed. We can provide no assurances as to how long these wider differentials may persist, and as noted above, these price differentials could widen further in future periods. In addition, we have no derivative contracts in place to mitigate our exposure to these oil and natural gas price differentials during 2019 and have limited oil basis hedges in place for 2020. +These widening basis differentials are largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. At February 26, 2019 , we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. During the third quarter of 2018, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin and elsewhere. We did not experience such problems in the third quarter of 2018 and have not experienced such problems since then. Although we do not expect to encounter fractionation capacity problems going forward, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Coinciding with the improvements in oil prices during the first three quarters of 2018, we experienced price increases from our service providers for some of the products and services we use in our drilling, completion and production operations. If oil and natural gas prices remain at their current levels for a longer period of time or should they increase further, we would anticipate receiving additional price increases for drilling, completion and production products and services, although we can provide no assurances as to the eventual magnitude of these increases. In addition, we attempt to avoid long-term service agreements where possible in order to minimize ongoing future commitments. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, in early 2019, separate bills were introduced in the New Mexico Senate proposing to add a surtax on natural gas processors and proposing to place a moratorium on hydraulic fracturing. New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Such laws, rules and regulations, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +79 +Table of Contents +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2018 . +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related reserves. +80 +Table of Contents +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. These instruments typically consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. +In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized gain (loss) on derivatives.” Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under Revenues as “Realized gain (loss) on derivatives.” +Revenue Recognition +During the first quarter of 2018, we adopted Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve the financial reporting requirements for revenue from contracts with customers and converge these requirements with international standards. We adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on our consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows. +Prior to the adoption of ASC 606, we recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser. We followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on our actual proceeds from the oil and natural gas sold to purchasers. +We enter into contracts with customers to sell our oil and natural gas production. With the adoption of ASC 606, revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when our performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration we expect to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of our oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on our consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +Our natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of our natural gas is sold under fee-based +81 +Table of Contents +contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas and transports the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if we elect to take in-kind the natural gas or NGLs, we sell the natural gas or NGLs to a third party. Under the fee-based contracts, we receive NGL and residue gas value, less the fee component, or are invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on our consolidated statements of operations. +We recognize midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. All midstream services revenues related to our working interest are eliminated in consolidation. Since we have a right to payment from our customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, we apply the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +We periodically enter into natural gas purchase transactions with third parties whereby we process the third party’s natural gas at the Black River Processing Plant and then purchase, and subsequently sell, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on our consolidated statements of operations as we act as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, we, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of our mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed, and we have no further obligation to the lessee. We record these payments as “Lease bonus - mineral acreage” revenues on our consolidated statements of operations. +Stock-Based Compensation +We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. Since 2012, all stock-based awards have been granted under the 2012 Long-Term Incentive Plan or, for awards granted after June 10, 2015, under the Amended and Restated 2012 Long-Term Incentive Plan, and substantially all of these awards as of December 31, 2018 were equity instruments. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan and are accounted for as liability instruments. We use the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock. +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the fair value of our stock on the date of the grant. See Note 8 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2018 . +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any +82 +Table of Contents +deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 7 to the consolidated financial statements in this Annual Report for additional information of the impact of the 2017 Tax Cuts and Jobs Act to our consolidated financial statements. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” +Recent Accounting Pronouncements +See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option have different fixed price +83 +Table of Contents +components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2018 , The Bank of Nova Scotia and SunTrust Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2018 , we had entered into various costless collar, three-way costless collar and swap contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with (i) an established price floor and ceiling for the costless collars, (ii) an established price floor and fixed prices for the short call (the ceiling) and the long call and (iii) a fixed price for the swaps. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of the costless collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. When the settlement price is above the fixed price of the sold call established by one or more of the three-way costless collars but below the fixed price of the long call established by one or more of these three-way costless collars, we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price of the sold call multiplied by the contract oil or natural gas volume. When the settlement price is above the fixed price of the long call established by one or more of the three-way costless collars, we pay to the counterparty an amount equal to the difference between the fixed price of the long call and the fixed price of the sold call multiplied by the contract oil or natural gas volume. +During the year ended December 31, 2018 , we entered into various swap contracts to mitigate our exposure to price differences between NYMEX West Texas Intermediate Cushing and Argus West Texas Intermediate Midland crude oil. When the settlement price is below the fixed price established by one or more of these swaps, we receive from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by one or more of these swaps, we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. +See Note 11 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2018 . Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2018 , we had outstanding borrowings of $40.0 million at an interest rate of 3.68% per annum under our Credit Agreement, $1.05 billion in Notes outstanding at a coupon rate of 5.875% per annum and $220.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 4.01% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the +84 +Table of Contents +circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 26, 2019 were The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), which are lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2018, 2017 and 2016 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report. See the index to the financial statements in Item 15. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2018 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2018 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2018 as included herein. +85 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +86 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2018 and 2017 , the related statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018 , and the related notes (collectively, the “consolidated financial statements”), and our report dated March 1, 2019 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +March 1, 2019 +87 +Table of Contents +Item 9B. Other Information. +On February 27, 2019, we entered into a First Supplemental Indenture (the “Supplemental Indenture”) with Wells Fargo Bank, National Association, as trustee (the “Trustee”), which supplements the Indenture, dated as of August 21, 2018 (the “Indenture”), among Matador, the subsidiary guarantors party thereto and the Trustee. Pursuant to the Supplemental Indenture, WR Permian, LLC, a wholly-owned subsidiary of Matador, was added as a party to and as a guarantor under the Indenture. +The foregoing description of the Supplemental Indenture does not purport to be complete and is qualified in its entirety by reference to the Supplemental Indenture, which is included in this Annual Report as Exhibit 4.3 and is incorporated herein by reference. +On February 26, 2019, our Board of Directors (the “Board”) approved the Matador Resources Company Annual Cash Incentive Plan (the “Plan”). The purpose of the Plan is to provide executives, select managers and key employees of the Company and its subsidiaries with cash-based incentive compensation opportunities tied to the achievement of one or more financial, operational or other performance goals established by the independent members of the Board or any other committee designated by the Board to administer the Plan. Each of the Company’s executive officers are eligible to participate in the Plan. The independent members of the Board, in their sole discretion, will establish the target award opportunities for each Plan participant, the applicable performance period and the performance goals for such performance period, and will ultimately determine Plan payouts in accordance with the terms of the Plan. The foregoing description of the Plan does not purport to be complete and is qualified in its entirety by reference to Plan, which is included in this Annual Report as Exhibit 10.66 and is incorporated herein by reference. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2019 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” The information required in response to this Item 10 with respect to compliance with Section 16(a) of the Exchange Act is incorporated herein by reference to our Definitive Proxy Statement under the caption “Section 16(a) Beneficial Ownership Reporting Compliance.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 5—Ratification of Appointment of KPMG LLP.” +. +88 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2018 and 2017 , Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016 . +2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report. +89 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).* +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018). +4.3 +First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (filed herewith). +4.4 +Registration Rights Agreement, dated August 21, 2018, by and among the Company, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on August 21, 2018). +4.5 +Registration Rights Agreement, dated October 4, 2018, by and among the Company, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on October 4, 2018). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +90 +Table of Contents +10.8† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.10† +Matador Resources Company Amended and Restated Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 14, 2016). +10.11† +Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.12† +First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.13† +Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.14† +Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.15† +Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.16† +Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.17† +Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.18† +Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.19† +Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.20† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.21† +Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.22† +Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.23† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011). +10.24† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +10.25† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). +91 +Table of Contents +10.26 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.27 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.28 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.29 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.30 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.31 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.32 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.33 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.34 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.35 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.36 +Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016). +10.37 +Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016). +10.38 +Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017) +10.39† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.40† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +92 +Table of Contents +10.41† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.42† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.43† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.44† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.45† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.46† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.62 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.47† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.48† +Form of Letter Agreement between Matador Resources Company and certain directors modifying Restricted Stock Unit Award Agreements (incorporated by reference to Exhibit 10.64 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.49† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.50† +Form of Restricted Stock Unit Award Agreement for Annual Grants relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.51† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.52† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.53† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.54† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.55† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.56† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.57† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.58† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +93 +Table of Contents +10.59† +First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.60† +Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.61 +Purchase Agreement, dated as of August 7, 2018, by and among the Company, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on August 9, 2018). +10.62 +Purchase Agreement, dated as of October 1, 2018, by and among the Company, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2018). +10.63 +Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 9, 2018). +10.64 +Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of October 1, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 4, 2018). +10.65 +Thirteenth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 1, 2018). +10.66† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (filed herewith). +10.67† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (filed herewith). +10.68† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +† +Indicates a management contract or compensatory plan or arrangement. +* +Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +94 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +March 1, 2019 +By: +/s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Joseph Wm. Foran +Chairman and Chief Executive Officer +March 1, 2019 +Joseph Wm. Foran +(Principal Executive Officer) +/s/ David E. Lancaster +Executive Vice President and Chief Financial Officer +March 1, 2019 +David E. Lancaster +(Principal Financial Officer) +/s/ Robert T. Macalik +Senior Vice President and Chief Accounting Officer +March 1, 2019 +Robert T. Macalik +(Principal Accounting Officer) +/s/ Reynald A. Baribault +Director +March 1, 2019 +Reynald A. Baribault +/s/ R. Gaines Baty +Director +March 1, 2019 +R. Gaines Baty +/s/ Craig T. Burkert +Director +March 1, 2019 +Craig T. Burkert +/s/ William M. Byerley +Director +March 1, 2019 +William M. Byerley +/s/ Matthew P. Clifton +Director +March 1, 2019 +Matthew P. Clifton +/s/ Julia P. Forrester Rogers +Director +March 1, 2019 +Julia P. Forrester Rogers +/s/ Timothy E. Parker +Director +March 1, 2019 +Timothy E. Parker +/s/ David M. Posner +Director +March 1, 2019 +David M. Posner +/s/ Kenneth L. Stewart +Director +March 1, 2019 +Kenneth L. Stewart +95 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or salt water. +Bcf . One billion cubic feet of natural gas. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +96 +Table of Contents +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or salt water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +97 +Table of Contents +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +98 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2018, 2017 and 2016 +Contents +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2018 and 2017 +F-3 +Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016 +F-4 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016 +F-5 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016 +F-6 +Notes to Consolidated Financial Statements +F-7 +Unaudited Supplementary Information +F-41 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (collectively the “Company”) as of December 31, 2018 and 2017 and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2018 , and the related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018 , in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +March 1, 2019 +F-2 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2018 +2017 +ASSETS +Current assets +Cash +$ +64,545 +$ +96,505 +Restricted cash +19,439 +5,977 +Accounts receivable +Oil and natural gas revenues +68,161 +65,962 +Joint interest billings +61,831 +67,225 +Other +16,159 +8,031 +Derivative instruments +49,929 +1,190 +Lease and well equipment inventory +17,564 +5,993 +Prepaid expenses and other assets +8,057 +6,287 +Total current assets +305,685 +257,170 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +3,780,236 +3,004,770 +Unproved and unevaluated +1,199,511 +637,396 +Midstream and other property and equipment +450,066 +281,096 +Less accumulated depletion, depreciation and amortization +(2,306,949 +) +(2,041,806 +) +Net property and equipment +3,122,864 +1,881,456 +Other assets +Deferred income taxes +20,457 +— +Other assets +6,512 +7,064 +Total other assets +26,969 +7,064 +Total assets +$ +3,455,518 +$ +2,145,690 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +66,970 +$ +11,757 +Accrued liabilities +170,855 +174,348 +Royalties payable +64,776 +61,358 +Amounts due to affiliates +13,052 +10,302 +Derivative instruments +— +16,429 +Advances from joint interest owners +10,968 +2,789 +Amounts due to joint ventures +2,373 +4,873 +Other current liabilities +1,028 +750 +Total current liabilities +330,022 +282,606 +Long-term liabilities +Borrowings under Credit Agreement +40,000 +— +Borrowings under San Mateo Credit Facility +220,000 +— +Senior unsecured notes payable +1,037,837 +574,073 +Asset retirement obligations +29,736 +25,080 +Derivative instruments +83 +— +Deferred income taxes +13,221 +— +Other long-term liabilities +4,962 +6,385 +Total long-term liabilities +1,345,839 +605,538 +Commitments and contingencies (Note 13) +Shareholders’ equity +Common stock — $0.01 par value, 160,000,000 shares authorized; 116,374,503 and 108,513,597 shares issued; and 116,353,590 and 108,510,160 shares outstanding, respectively +1,164 +1,085 +Additional paid-in capital +1,924,408 +1,666,024 +Accumulated deficit +(236,277 +) +(510,484 +) +Treasury stock, at cost, 20,913 and 3,437 shares, respectively +(415 +) +(69 +) +Total Matador Resources Company shareholders’ equity +1,688,880 +1,156,556 +Non-controlling interest in subsidiaries +90,777 +100,990 +Total shareholders’ equity +1,779,657 +1,257,546 +Total liabilities and shareholders’ equity +$ +3,455,518 +$ +2,145,690 +The accompanying notes are an integral part of these consolidated financial statements. +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2018 +2017 +2016 +Revenues +Oil and natural gas revenues +$ +800,700 +$ +528,684 +$ +291,156 +Third-party midstream services revenues +21,920 +10,198 +5,218 +Sales of purchased natural gas +7,071 +— +— +Lease bonus - mineral acreage +2,489 +— +— +Realized gain (loss) on derivatives +2,334 +(4,321 +) +9,286 +Unrealized gain (loss) on derivatives +65,085 +9,715 +(41,238 +) +Total revenues +899,599 +544,276 +264,422 +Expenses +Production taxes, transportation and processing +76,138 +58,275 +43,046 +Lease operating +92,966 +67,313 +56,202 +Plant and other midstream services operating +24,609 +13,039 +5,389 +Purchased natural gas +6,635 +— +— +Depletion, depreciation and amortization +265,142 +177,502 +122,048 +Accretion of asset retirement obligations +1,530 +1,290 +1,182 +Full-cost ceiling impairment +— +— +158,633 +General and administrative +69,308 +66,016 +55,089 +Total expenses +536,328 +383,435 +441,589 +Operating income (loss) +363,271 +160,841 +(177,167 +) +Other income (expense) +Net (loss) gain on asset sales and inventory impairment +(196 +) +23 +107,277 +Interest expense +(41,327 +) +(34,565 +) +(28,199 +) +Prepayment premium on extinguishment of debt +(31,226 +) +— +— +Other income (expense) +1,551 +3,551 +(4 +) +Total other (expense) income +(71,198 +) +(30,991 +) +79,074 +Income (loss) before income taxes +292,073 +129,850 +(98,093 +) +Income tax (benefit) provision +Current +(455 +) +(8,157 +) +(1,036 +) +Deferred +(7,236 +) +— +— +Total income tax benefit +(7,691 +) +(8,157 +) +(1,036 +) +Net income (loss) +299,764 +138,007 +(97,057 +) +Net income attributable to non-controlling interest in subsidiaries +(25,557 +) +(12,140 +) +(364 +) +Net income (loss) attributable to Matador Resources Company shareholders +$ +274,207 +$ +125,867 +$ +(97,421 +) +Earnings (loss) per common share +Basic +$ +2.41 +$ +1.23 +$ +(1.07 +) +Diluted +$ +2.41 +$ +1.23 +$ +(1.07 +) +Weighted average common shares outstanding +Basic +113,580 +102,029 +91,273 +Diluted +113,691 +102,543 +91,273 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2018, 2017 and 2016 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital +Accumulated deficit +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders ’ equity +Common Stock +Shares +Amount +Shares +Amount +Balance at January 1, 2016 +85,567 +$ +856 +$ +1,026,077 +$ +(538,930 +) +2 +$ +— +$ +488,003 +$ +956 +$ +488,959 +Issuance of common stock pursuant to public offerings +13,500 +135 +288,375 +— +— +— +288,510 +— +288,510 +Issuance of common stock pursuant to employee stock compensation plan +471 +4 +(4 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +51 +1 +(1 +) +— +— +— +— +— +— +Cost to issue equity +— +— +(1,190 +) +— +— +— +(1,190 +) +— +(1,190 +) +Stock-based compensation expense related to equity-based awards +— +— +11,958 +— +— +— +11,958 +— +11,958 +Stock options exercised, net of options forfeited in net share settlements +36 +— +10 +— +— +— +10 +— +10 +Liability-based stock option awards settled +10 +— +255 +— +— +— +255 +— +255 +Restricted stock forfeited +— +— +— +— +120 +— +— +— +— +Cancellation of treasury stock +(116 +) +(1 +) +1 +— +(116 +) +— +— +— +— +Current period net (loss) income +— +— +— +(97,421 +) +— +— +(97,421 +) +364 +(97,057 +) +Balance at December 31, 2016 +99,519 +995 +1,325,481 +(636,351 +) +6 +— +690,125 +1,320 +691,445 +Issuance of common stock pursuant to public offering +8,000 +80 +208,640 +— +— +— +208,720 +— +208,720 +Issuance of common stock pursuant to employee stock compensation plan +530 +5 +(5 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +77 +1 +(1 +) +— +— +— +— +— +— +Cost to issue equity +— +— +(280 +) +— +— +— +(280 +) +— +(280 +) +Stock-based compensation expense related to equity-based awards including amounts capitalized +— +— +19,594 +— +— +— +19,594 +— +19,594 +Stock options exercised, net of options forfeited in net share settlements +514 +5 +(1,189 +) +— +— +— +(1,184 +) +— +(1,184 +) +Restricted stock forfeited +— +— +— +— +123 +(1,658 +) +(1,658 +) +— +(1,658 +) +Purchase of non-controlling interest of less-than-wholly-owned subsidiary +— +— +(1,250 +) +— +— +— +(1,250 +) +(1,403 +) +(2,653 +) +Contributions related to formation of Joint Venture (see Note 5) +— +— +116,622 +— +— +— +116,622 +54,878 +171,500 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +44,100 +44,100 +Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries +— +— +— +— +— +— +— +(10,045 +) +(10,045 +) +Cancellation of treasury stock +(126 +) +(1 +) +(1,588 +) +— +(126 +) +1,589 +— +— +— +Current period net income +— +— +— +125,867 +— +— +125,867 +12,140 +138,007 +Balance at December 31, 2017 +108,514 +1,085 +1,666,024 +(510,484 +) +3 +(69 +) +1,156,556 +100,990 +1,257,546 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital +Accumulated deficit +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders ’ equity +Common Stock +Shares +Amount +Shares +Amount +Issuance of common stock pursuant to employee stock compensation plan +759 +8 +(8 +) +— +— +— +— +— +— +Issuance of common stock pursuant to public offering +7,000 +70 +226,542 +— +— +— +226,612 +— +226,612 +Cost to issue equity +— +— +(204 +) +— +— +— +(204 +) +— +(204 +) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +81 +1 +(1 +) +— +— +— +— +— +— +Stock-based compensation expense related to equity-based awards including amounts capitalized +— +— +22,660 +— +— +— +22,660 +— +22,660 +Stock options exercised, net of options forfeited in net share settlements +179 +2 +(1,269 +) +— +— +— +(1,267 +) +— +(1,267 +) +Restricted stock forfeited +— +— +— +— +176 +(4,384 +) +(4,384 +) +— +(4,384 +) +Contributions related to formation of Joint Venture (see Note 5) +— +— +14,700 +— +— +— +14,700 +— +14,700 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +85,750 +85,750 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +(121,520 +) +(121,520 +) +Cancellation of treasury stock +(158 +) +(2 +) +(4,036 +) +— +(158 +) +4,038 +— +— +— +Current period net income +— +— +— +274,207 +— +— +274,207 +25,557 +299,764 +Balance at December 31, 2018 +116,375 +$ +1,164 +$ +1,924,408 +$ +(236,277 +) +21 +$ +(415 +) +$ +1,688,880 +$ +90,777 +$ +1,779,657 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +2018 +2017 +2016 +Operating activities +Net income (loss) +$ +299,764 +$ +138,007 +$ +(97,057 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized (gain) loss on derivatives +(65,085 +) +(9,715 +) +41,238 +Depletion, depreciation and amortization +265,142 +177,502 +122,048 +Accretion of asset retirement obligations +1,530 +1,290 +1,182 +Full-cost ceiling impairment +— +— +158,633 +Stock-based compensation expense +17,200 +16,654 +12,362 +Prepayment premium on extinguishment of debt +31,226 +— +— +Deferred income tax benefit +(7,236 +) +— +— +Amortization of debt issuance cost +1,357 +468 +1,148 +Net loss (gain) on asset sales and inventory impairment +196 +(23 +) +(107,277 +) +Changes in operating assets and liabilities +Accounts receivable +(4,934 +) +(82,549 +) +(14,259 +) +Lease and well equipment inventory +(12,176 +) +(3,623 +) +(700 +) +Prepaid expenses and other assets +(1,770 +) +(2,960 +) +(124 +) +Other assets +3,418 +(6,425 +) +490 +Accounts payable, accrued liabilities and other current liabilities +68,647 +33,559 +6,611 +Royalties payable +3,418 +37,370 +7,495 +Advances from joint interest owners +8,179 +1,089 +1,000 +Income taxes payable +— +— +(2,848 +) +Other long-term liabilities +(353 +) +(1,519 +) +4,144 +Net cash provided by operating activities +608,523 +299,125 +134,086 +Investing activities +Oil and natural gas properties capital expenditures +(1,357,802 +) +(699,445 +) +(379,067 +) +Expenditures for midstream and other property and equipment +(165,784 +) +(120,816 +) +(74,845 +) +Proceeds from sale of assets +8,333 +977 +5,173 +Net cash used in investing activities +(1,515,253 +) +(819,284 +) +(448,739 +) +Financing activities +Repayments of borrowings +(370,000 +) +— +(120,000 +) +Borrowings under Credit Agreement +410,000 +— +120,000 +Borrowings under San Mateo Credit Facility +220,000 +— +— +Cost to enter into or amend credit facilities +(3,077 +) +— +— +Proceeds from issuance of senior unsecured notes +1,051,500 +— +184,625 +Cost to issue senior unsecured notes +(14,098 +) +— +(2,734 +) +Purchase of senior unsecured notes +(605,780 +) +— +— +Proceeds from issuance of common stock +226,612 +208,720 +288,510 +Cost to issue equity +(204 +) +(280 +) +(847 +) +Proceeds from stock options exercised +815 +2,920 +100 +Contributions related to formation of Joint Venture +14,700 +171,500 +— +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +85,750 +44,100 +— +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries +(121,520 +) +(10,045 +) +— +Taxes paid related to net share settlement of stock-based compensation +(6,466 +) +(5,763 +) +(1,948 +) +Purchase of non-controlling interest of less-than-wholly-owned subsidiary +— +(2,653 +) +— +Net cash provided by financing activities +888,232 +408,499 +467,706 +(Decrease) increase in cash and restricted cash +(18,498 +) +(111,660 +) +153,053 +Cash and restricted cash at beginning of year +102,482 +214,142 +61,089 +Cash and restricted cash at end of year +$ +83,984 +$ +102,482 +$ +214,142 +Supplemental disclosures of cash flow information (Note 14) +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2018, 2017 and 2016 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Change in Accounting Principles — Revenue Recognition +During the first quarter of 2018, the Company adopted Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve and converge with international standards, the financial reporting requirements for revenue from contracts with customers. The Company adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on the Company’s consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows. +Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers. +The Company enters into contracts with customers to sell its oil and natural gas production. With the adoption of ASC 606, revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, natural gas liquids (“NGL”) are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. +The Company determined the impact on its consolidated financial statements as a result of adoption of ASC 606 was a $10.6 million decrease in oil and natural gas revenues and a $10.6 million decrease in production taxes, transportation and processing expenses for the year ended December 31, 2018 , respectively, which was not material. As a result of adoption of this standard, the Company is now required to disclose the following information regarding total revenues and revenues from contracts with customers on a disaggregated basis for the year ended December 31, 2018 (in thousands). +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Year Ended +December 31, 2018 +Revenues from contracts with customers +$ +829,691 +Lease bonus - mineral acreage +2,489 +Realized gain on derivatives +2,334 +Unrealized gain on derivatives +65,085 +Total revenues +$ +899,599 +Year Ended +December 31, 2018 +Oil revenues +$ +635,554 +Natural gas revenues +165,146 +Third-party midstream services revenues +21,920 +Sales of purchased natural gas +7,071 +Total revenues from contracts with customers +$ +829,691 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Change in Accounting Principles — Cash Flows +During the first quarter of 2018, the Company adopted Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230) , which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The Company adopted ASU 2016-18 effective January 1, 2018 and determined that the adoption of this ASU changed the presentation of its beginning and ending cash balances and eliminated the presentation of changes in restricted cash balances from investing activities in its consolidated statements of cash flows. The Company adopted the new guidance using the retrospective transition method; as a result, approximately $6.0 million , $1.3 million and $44.4 million of restricted cash was added to the beginning cash balance for the years ended December 31, 2018 , 2017 and 2016 , respectively. +Change in Accounting Principles — Business Combinations +During the first quarter of 2018, the Company adopted ASU 2017-01, Business Combinations (Topic 805) , which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. The Company adopted ASU 2017-01 prospectively, which did not have a material impact on its consolidated financial statements. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and NGL production to various purchasers (See “—Change in Accounting Principles—Revenue Recognition” above.) In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2018 , four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 19% ), BP America Production Company ( 15% ), Occidental Energy Marketing, Inc. ( 14% ) and Western Refining Crude Oil ( 12% ). For the year ended December 31, 2017 , four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL revenues: Occidental Energy Marketing, Inc. ( 23% ), Plains Marketing, L.P. ( 14% ), Shell Trading (US) Company ( 12% ), and Western Refining Crude Oil ( 11% ). For the year ended December 31, 2016 , three significant purchasers accounted for 48% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 18% ), Shell Trading (US) Company ( 17% ) and Occidental Energy Marketing, Inc. ( 13% ). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2018, 2017 and 2016 , approximately 34% , 43% and 38% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $29.9 million , $23.1 million and $15.7 million of its general and administrative costs in 2018 , 2017 and 2016 , respectively. The Company capitalized $8.8 million , $7.3 million and $3.7 million of its interest expense for the years ended December 31, 2018, 2017 and 2016 , respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2018 , these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the years ended December 31, 2018 and December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2018 and 2017. +During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million , exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance. +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream and Other Property and Equipment +Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the consolidated statements of operations on a straight-line basis over the awards’ vesting periods. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are generally recognized as a component of general and administrative expenses in the consolidated statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the Company’s 2003 Stock and Incentive Plan (the “2003 Plan”) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options. As the stock options accounted for as liability-based awards are fully vested, changes in the fair value of the awards are generally recognized as a component of general and administrative expenses in the consolidated statements of operations until the awards are settled. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units. +The Company’s consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016 include a stock-based compensation (non-cash) expense of $17.2 million , $16.7 million and $12.4 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.6 million , $3.0 million and $1.0 million in 2018 , 2017 and 2016 , respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2018, 2017 and 2016 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2018, 2017 and 2016 . +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changed U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The Tax Cuts and Jobs Act reduced the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings (Loss) Per Common Share +The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2018, 2017 and 2016 (in thousands, except per share data). +Year Ended December 31, +2018 +2017 +2016 +Net income (loss) attributable to Matador Resources Company shareholders — numerator +$ +274,207 +$ +125,867 +$ +(97,421 +) +Weighted average common shares outstanding — denominator +Basic +113,580 +102,029 +91,273 +Dilutive effect of options and restricted stock units +111 +514 +— +Diluted weighted average common shares outstanding +113,691 +102,543 +91,273 +Earnings (loss) per common share attributable to +Matador Resources Company shareholders +Basic +$ +2.41 +$ +1.23 +$ +(1.07 +) +Diluted +$ +2.41 +$ +1.23 +$ +(1.07 +) +Options to purchase a total of 1.6 million and 1.0 million shares of the Company’s common stock were excluded from the calculations above for the years ended December 31, 2018 and 2017 , respectively, because their effects were anti-dilutive. +Options to purchase a total of 2.9 million shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Company’s commodity derivative contracts at December 31, 2018 were with The Bank of Nova Scotia and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Leases . In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842) , which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient. The Company plans to use this practical expedient, and as a result, the Company will evaluate new or modified land easements under this ASU beginning at the date of adoption. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842) , which is a targeted improvement for comparative reporting requirements for initial adoption of ASU 2016-02. The Company plans to use the optional transition method to adopt ASU 2016-02, and the amendments provided for in ASU 2018-11 will allow the Company to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of accumulated deficit in the period of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The Company has evaluated the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases as defined under the new lease standards, and estimates that adoption of these standards will result in assets and liabilities related to leases of approximately $55 million to $65 million to be reflected on the Company’s consolidated balance sheet. The Company adopted these ASUs as of January 1, 2019. +Stock Compensation . In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting . This ASU extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Currently, the Company accounts for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards is recalculated each reporting period. Upon adoption, all such awards will be measured at fair value on the grant date and the resulting expense will be recognized on a straight-line basis over the awards’ vesting period. The transitional guidance requires entities to remeasure all unvested awards that are being accounted for under ASC 505-50 as liability instruments as of the beginning of the year in which this ASU is adopted. The Company adopted this ASU as of January 1, 2019. Adoption of this ASU will not have a material impact on the Company’s consolidated financial statements. +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2018 and 2017 (in thousands). +December 31, +2018 +2017 +Oil and natural gas properties +Evaluated (subject to amortization) +$ +3,780,236 +$ +3,004,770 +Unproved and unevaluated (not subject to amortization) +1,199,511 +637,396 +Total oil and natural gas properties +4,979,747 +3,642,166 +Accumulated depletion +(2,273,010 +) +(2,021,169 +) +Net oil and natural gas properties +2,706,737 +1,620,997 +Midstream and other property and equipment +Midstream equipment and facilities +424,480 +258,725 +Furniture, fixtures and other equipment +7,184 +6,109 +Software +8,039 +7,942 +Land +4,192 +2,892 +Leasehold improvements +6,171 +5,428 +Total midstream and other property and equipment +450,066 +281,096 +Accumulated depreciation +(33,939 +) +(20,637 +) +Net midstream and other property and equipment +416,127 +260,459 +Net property and equipment +$ +3,122,864 +$ +1,881,456 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2018 and the year in which these costs were incurred (in thousands). +Description +2018 +2017 +2016 +2015 and prior +Total +Costs incurred for +Property acquisition +$ +602,117 +$ +212,846 +$ +116,389 +$ +223,656 +$ +1,155,008 +Exploration wells +12,361 +1,235 +712 +204 +14,512 +Development wells +29,399 +391 +159 +42 +29,991 +Total +$ +643,877 +$ +214,472 +$ +117,260 +$ +223,902 +$ +1,199,511 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2018 are related almost entirely to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past five years. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +On September 12, 2018, the Company announced the successful acquisition of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”). The BLM Acquisition was responsible for a significant portion of the Company’s property acquisition costs in 2018. +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $44.5 million at December 31, 2018 . Of this total, $14.5 million was associated with exploration wells and $30.0 million was associated with development wells. The Company anticipates that most of the $44.5 million associated with these wells in progress at December 31, 2018 will be transferred to the amortization base during 2019 . +NOTE 4 — ASSET RETIRMENT OBLIGATIONS +In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2018 and 2017 (in thousands). +Year Ended December 31, +2018 +2017 +Beginning asset retirement obligations +$ +26,256 +$ +20,640 +Liabilities incurred during period +3,566 +2,920 +Liabilities settled during period +(708 +) +(430 +) +Revisions in estimated cash flows +442 +1,836 +Accretion expense +1,530 +1,290 +Ending asset retirement obligations +31,086 +26,256 +Less: current asset retirement obligations (1) +(1,350 +) +(1,176 +) +Long-term asset retirement obligations +$ +29,736 +$ +25,080 +__________________ +(1) +Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2018 and 2017 . +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES +Joint Venture +On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo, a joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo’s other assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of San Mateo. +The Company and Five Point own 51% and 49% of San Mateo, respectively. Five Point provided initial cash consideration of $176.4 million to San Mateo in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by San Mateo to the Company as a special distribution. The Company earned $14.7 million in performance incentives effective January 31, 2018, which was paid by Five Point in the first quarter of 2018. Through January 31, 2019, the Company had earned an additional $14.7 million in performance incentives expected to be paid by Five Point in the first quarter of 2019 and may earn an additional $44.1 million in performance incentives over the next three years . These performance incentives are recorded as additional contributions related to the formation of the Joint Venture as +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +they are received. The Company contributed the Delaware Midstream Assets and $5.1 million in cash to San Mateo in exchange for its 51% interest. San Mateo is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo being accounted for as a non-controlling interest. +The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas to San Mateo pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15 -year, fixed-fee natural gas processing agreement (see Note 13). +Divestitures +On October 1, 2015, the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant. +Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million , and the Company received net proceeds of approximately $139.8 million after deducting customary purchase price adjustments of approximately $3.6 million . In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement. +Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15 -year term of the gathering and processing agreement. +During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink began processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing agreement the Company entered into with EnLink was no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016. +The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017, these assets were contributed to San Mateo. +NOTE 6 — DEBT +Credit Agreements +MRC Energy Company +On September 28, 2012 , the Company amended and restated its revolving credit agreement with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company, a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of certain of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 6 — DEBT — Continued +each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. During the first quarter of 2018, the lenders completed their review of our proved oil and natural gas reserves at December 31, 2017. As a result, in March 2018, the lenders increased the borrowing base from $525.0 million to $725.0 million . In October 2018, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2018. In connection with that review, the Company amended the Credit Agreement to, among other items, increase the borrowing base from $725.0 million to $850.0 million , increase the maximum facility amount to $1.5 billion , increase the elected borrowing commitment to $500.0 million , extend the maturity to October 31, 2023, reduce the borrowing rates by 0.25% per annum and set the maximum leverage ratio at 4.00 to 1.00 . This October 2018 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment. +In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. Total deferred loan costs were $2.0 million at December 31, 2018 , and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +At December 31, 2018 , the Company had $40.0 million in borrowings outstanding under the Credit Agreement and approximately $3.0 million in outstanding letters of credit issued pursuant to the Credit Agreement. At February 26, 2019 , the Company had $80.0 million in borrowings outstanding under the Credit Agreement and approximately $13.7 million in outstanding letters of credit issued pursuant to the Credit Agreement. +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount ranging from 0.25% to 1.25% per annum depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25% to 2.25% per annum depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. If the Company has outstanding borrowings under the Credit Agreement and interest rates increase, so will the Company’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375% to 0.50% per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of the Company’s assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; +• +engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 6 — DEBT — Continued +• +take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving the Company or its subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2018 . +San Mateo Midstream, LLC +On December 19, 2018, San Mateo entered into a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and including all lenders party to the Credit Agreement. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which could expand lender commitments to up to $400.0 million . The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. +Total deferred loan costs were $ 1.9 million at December 31, 2018, and these costs are being amortized over the term of the San Mateo Credit Facility, which approximates amortization of these costs using the effective interest method. At December 31, 2018 and February 26, 2019 , San Mateo had $220.0 million in borrowings outstanding under the San Mateo Credit Facility and zero and $16.2 million , respectively, in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 0.50% to 1.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50% to 2.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +A commitment fee of 0.30% to 0.50% per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of San Mateo’s assets; +• +enter into hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 6 — DEBT — Continued +• +make any loans or investments; +• +engage in transactions with affiliates; +• +engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and +• +issue equity interests in San Mateo or its subsidiaries. +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving San Mateo or its subsidiaries; and +• +a change of control, as defined in the San Mateo Credit Facility. +The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2018. +Senior Unsecured Notes +On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original 2023 Notes”) in a private placement at par value. The Original 2023 Notes were later exchanged for a like principal amount of 6.875% senior notes due 2023 (the “2023 Exchange Notes”) that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), at par value. On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional 2023 Notes”) in a private placement, at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5% . The Company received net proceeds of approximately $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional 2023 Notes. The Additional 2023 Notes were later exchanged for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (together with the 2023 Exchange Notes, the “2023 Notes”). +On August 21, 2018, the Company issued $750.0 million of 5.875% senior notes due 2026 (the “Original 2026 Notes”) in a private placement at par value (the “2026 Notes Offering”). The Company received net proceeds of approximately $740.0 million , after deducting the initial purchasers’ discounts and offering expenses. In conjunction with the 2026 Notes Offering, in August and September 2018, respectively, the Company completed a tender offer to purchase for cash and subsequent redemption of all of the 2023 Notes (the “2023 Notes Tender Offer and Redemption”). The Company used a portion of the net proceeds from the 2026 Notes Offering to fund the 2023 Notes Tender Offer and Redemption. In connection with the 2023 Notes Tender Offer and Redemption, the Company incurred a loss of $31.2 million , including total payments of $30.4 million to holders of the 2023 Notes as a result of the tender premium and the required 105.156% redemption price payable pursuant to the 2023 Notes indenture. +On October 4, 2018, the Company issued an additional $300.0 million of 5.875% senior notes due 2026 (the “Additional 2026 Notes”). The Additional 2026 Notes were issued pursuant to, and are governed by, the same indenture governing the Original 2026 Notes (the “Indenture”). The Additional 2026 Notes were issued at 100.5% of par, plus accrued interest from August 21, 2018. The Company received net proceeds from this offering of approximately $297.3 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest from August 21, 2018 paid by the initial purchasers of the Additional 2026 Notes. The proceeds from this offering were used to repay a portion of the outstanding borrowings under the Credit Agreement, which were incurred in connection with the BLM Acquisition. +In December 2018, the Company exchanged substantially all of the Original 2026 Notes and Additional 2026 Notes for a like principal amount of 5.875% senior notes due 2026 that have been registered under the Securities Act (the “Notes”). The terms of the Notes are substantially the same as the terms of the Original 2026 Notes and Additional 2026 Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original 2026 Notes and Additional 2026 Notes do not apply to the Notes. The Notes will mature September 15, 2026, and interest is payable on the Notes semi- +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 6 — DEBT — Continued +annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries under the Indenture or Guarantors of the Notes (see Note 16). +On or after September 15, 2021, the Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: +Year +Redemption Price +2021 +104.406% +2022 +102.938% +2023 +101.469% +2024 and thereafter +100.000% +At any time prior to September 15, 2021, the Company may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 105.875% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by the Company and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. +In addition, at any time prior to September 15, 2021, the Company may redeem all or part of the Notes at a redemption price equal to the sum of: +(i) the principal amount thereof, plus +(ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at September 15, 2021 plus (2) any required interest payments due on such Notes through September 15, 2021, discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus +(iii) accrued and unpaid interest, if any, to the redemption date. +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur additional indebtedness; +• +sell assets; +• +pay dividends or make certain investments; +• +create liens that secure indebtedness; +• +enter into transactions with affiliates; and +• +merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• +default for 30 days in the payment when due of interest on the Notes; +• +default in the payment when due of the principal of, or premium, if any, on the Notes; +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 6 — DEBT — Continued +• +failure by the Company to comply with its obligations to offer to purchase or purchase notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers; +• +failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture; +• +failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; +• +payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $50.0 million or more; +• +failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $50.0 million within 60 days; +• +any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• +certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +The outstanding borrowings of $40.0 million at December 31, 2018 under the Credit Agreement mature on October 31, 2023. The outstanding borrowings of $220.0 million at December 31, 2018 under the San Mateo Credit Facility mature on December 19, 2023. The $1.05 billion of outstanding Notes at December 31, 2018 mature on September 15, 2026. +NOTE 7 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2018 and 2017 is as follows (in thousands). +December 31, +2018 +2017 +Deferred tax assets +Unrealized loss on derivatives +$ +— +$ +3,200 +Net operating loss carryforwards +116,374 +118,134 +Percentage depletion carryover +1,624 +1,582 +Basis increase related to the San Mateo transaction +— +18,382 +Other +9,115 +— +Total deferred tax assets +127,113 +141,298 +Valuation allowance on deferred tax assets +(6,519 +) +(89,482 +) +Total deferred tax assets, net of valuation allowance +120,594 +51,816 +Deferred tax liabilities +Unrealized gain on derivatives +(10,468 +) +— +Property and equipment +(100,634 +) +(40,568 +) +Other +(2,256 +) +(11,248 +) +Total deferred tax liabilities +(113,358 +) +(51,816 +) +Net deferred tax assets +$ +7,236 +$ +— +At December 31, 2018 , the Company had net operating loss carryforwards of $511.3 million for federal income tax purposes and $156.4 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024 ; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . +At December 31, 2017 and 2016, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2016 and 2015. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at December 31, 2017 due to uncertainties regarding the future utilization of its deferred tax assets. Due to a variety +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 7 — INCOME TAXES — Continued +of factors, including the Company’s significant net income in 2017 and 2018, the Company’s federal valuation allowance and a portion of the Company’s state valuation allowance were reversed at December 31, 2018 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. +The current income tax (benefit) provision and the deferred income tax (benefit) provision for the years ended December 31, 2018, 2017 and 2016 were comprised of the following (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Current income tax (benefit) provision +Federal income tax +$ +(455 +) +$ +(8,178 +) +$ +(1,144 +) +State income tax +— +21 +108 +Net current income tax benefit +$ +(455 +) +$ +(8,157 +) +$ +(1,036 +) +Deferred income tax (benefit) provision +Federal income tax +$ +(20,457 +) +$ +— +$ +— +State income tax +13,221 +— +— +Net deferred income tax benefit +$ +(7,236 +) +$ +— +$ +— +Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax benefit for the years ended December 31, 2018, 2017 and 2016 is as follows (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Federal tax expense (benefit) at statutory rate (1) +$ +61,543 +$ +45,447 +$ +(34,333 +) +State income tax +16,181 +368 +539 +Permanent differences +(2,488 +) +(4,740 +) +(499 +) +Federal alternative minimum tax +— +— +1,144 +AMT credit refundable +455 +8,178 +— +Tax Cuts and Jobs Act rate change +— +51,525 +— +Change in federal valuation allowance +(80,003 +) +(101,917 +) +33,688 +Change in state valuation allowance +(2,924 +) +1,139 +(539 +) +Net deferred income tax benefit +(7,236 +) +— +— +Net current income tax benefit +(455 +) +(8,157 +) +(1,036 +) +Total income tax benefit +$ +(7,691 +) +$ +(8,157 +) +$ +(1,036 +) +__________________ +(1) +The statutory federal tax rate was 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2015 . The earliest tax year open for examination for the State of Texas tax return is 2014. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2018 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act, the Company revalued its deferred tax assets and liabilities at December 31, 2017, which resulted in a $51.5 million tax provision. As the Company maintained a valuation allowance against its federal and state deferred tax assets at December 31, 2017, a corresponding reduction in the valuation allowance was recorded against this +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 7 — INCOME TAXES — Continued +tax provision; therefore, there was no net impact to the Company’s consolidated statement of operations for the year ended December 31, 2017 as a result of this corporate income tax rate change. +Corporate alternative minimum taxes were also repealed under the Tax Cuts and Jobs Act; therefore, corporate alternative minimum tax carryforwards are expected to be refunded. As a result, the Company recorded $0.5 million and $8.2 million , respectively, as a current income tax benefit in its consolidated statements of operations for the years ended December 31, 2018 and 2017. +NOTE 8 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Plan. The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. +In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2018 , the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. +The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. At December 31, 2018, all stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and substantially all are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period. +Stock Options +Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or ten years. +The fair value of the 67,500 , 75,000 and 77,500 stock option awards outstanding under the 2003 Plan at December 31, 2018, 2017 and 2016 , respectively, was estimated using the following weighted average assumptions. +2018 +2017 +2016 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +1.14 years +2.14 years +3.14 years +Risk-free interest rate +2.48% +1.98% +1.70% +Volatility +37.94% +43.60% +47.07% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +—% +—% +—% +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2018, 2017 and 2016 . +2018 +2017 +2016 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +4.00 years +4.00 years +3.96 years +Risk-free interest rate +2.51% +1.77% +1.08% +Volatility +45.17% +47.00% +45.68% +Dividend yield +—% +—% +—% +Estimated forfeiture rate +2.24% +3.66% +1.16% +Weighted average fair value of stock option awards granted during the year +$12.64 +$10.49 +$5.65 +The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2018 under the 2003 Plan and the 2012 Incentive Plan is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2017 +3,064 +$ +21.14 +Options granted +563 +$ +29.68 +Options exercised +(383 +) +$ +13.84 +Options forfeited +(18 +) +$ +26.33 +Options expired +(1 +) +$ +26.86 +Options outstanding at December 31, 2018 +3,225 +$ +23.48 +Options outstanding at +December 31, 2018 +Options exercisable at +December 31, 2018 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life +Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$9.00 +68 +1.14 +$ +9.00 +68 +$ +9.00 +$13.22 - $15.00 +615 +2.13 +$ +14.98 +3 +$ +13.22 +$19.71 - $22.70 +727 +1.10 +$ +21.92 +706 +$ +21.93 +$23.40 - $29.68 +1,815 +3.91 +$ +26.79 +556 +$ +24.65 +At December 31, 2018 , the aggregate intrinsic value was $0.8 million for outstanding options and $0.4 million for exercisable options, based on the Company’s quoted closing market price of $15.53 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2018 was 2.88 years. +The total intrinsic value of options exercised during the years ended December 31, 2018, 2017 and 2016 was $7.0 million , $13.2 million and $1.6 million , respectively. The tax related benefit realized from the exercise of stock options totaled $5.7 million , $5.0 million and $0.5 million for the years ended December 31, 2018, 2017 and 2016 , respectively. +At December 31, 2018 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $9.3 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.65 years. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 8 — STOCK-BASED COMPENSATION — Continued +The fair value of options vested during 2018 , 2017 and 2016 was $11.8 million , $2.1 million and $3.0 million , respectively. +Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Restricted stock and restricted stock units granted in 2018, 2017 and 2016 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2018 were granted under the 2012 Incentive Plan. +A summary of the non-vested restricted stock and restricted stock units as of December 31, 2018 is presented below (in thousands, except fair value). +Restricted Stock +Restricted Stock Units +Non-vested restricted stock and +restricted stock units +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value +Non-vested at December 31, 2017 +1,104 +$ +22.59 +65 +$ +23.36 +Granted +759 +$ +29.45 +64 +$ +27.69 +Vested +(475 +) +$ +23.87 +(71 +) +$ +23.90 +Forfeited +(32 +) +$ +27.20 +— +— +Non-vested at December 31, 2018 +1,356 +$ +25.87 +58 +$ +27.48 +At December 31, 2018 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $22.0 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $15.53 per share on that date. +At December 31, 2018 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $22.0 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 0.90 years. +The fair value of restricted stock and restricted stock units vested during 2018 , 2017 and 2016 was $13.0 million , $9.9 million and $4.6 million , respectively. +Summary +During the years ended December 31, 2018, 2017 and 2016 , the total expense attributable to stock options was $6.3 million , $7.1 million and $5.9 million , respectively. At December 31, 2018, 2017 and 2016 , the Company recorded a decrease of $1.1 million and increases of $0.4 million and $1.4 million to long-term liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2018, 2017 and 2016 , respectively. +During the years ended December 31, 2018, 2017 and 2016 , the total expense attributable to restricted stock and restricted stock units was $15.3 million , $12.9 million and $6.6 million , respectively. During the year ended December 31, 2018 , the Company capitalized $4.4 million related to stock-based compensation and expensed the remaining $17.2 million . +The total tax benefit recognized for all stock-based compensation was $4.8 million , $6.8 million and $4.3 million for the years ended December 31, 2018, 2017 and 2016 , respectively. +In February 2019, the Company granted awards to certain of its employees of 428,005 service-based restricted stock units to be settled in cash, which are liability instruments, and 428,005 performance-based stock units, which are equity instruments. The performance-based stock units vest in an amount between zero and 200% based on the Company’s relative total shareholder return over the three -year period ending December 31, 2021, as compared to a designated peer group. The service-based restricted stock units vest ratably over three years, and the performance-based stock units vest after completion of the three -year performance period. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 9 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $1.1 million , $0.9 million and $0.7 million in 2018 , 2017 and 2016 , respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $1.4 million , $1.1 million and $0.9 million in 2018 , 2017 and 2016 , respectively. The Company made no additional contributions in any reporting period presented. +NOTE 10 — EQUITY +Common Stock +On May 17, 2018, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.2 million , the Company received net proceeds of approximately $226.4 million . The proceeds from this offering were used to acquire additional leasehold and mineral acres in the Delaware Basin, to fund certain midstream initiatives in the Delaware Basin and for general corporate purposes, including to fund a portion of the Company’s capital expenditures. Pending such uses, the Company used a portion of the proceeds from the offering to repay the $45.0 million in borrowings then outstanding under the Credit Agreement. +On October 10, 2017 , the Company completed a public offering of 8,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.3 million , the Company received net proceeds of approximately $208.4 million . +On June 1, 2017, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 120,000,000 to 160,000,000 shares. +On December 9, 2016 , the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million , the Company received net proceeds of approximately $145.8 million . On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million , the Company received net proceeds of approximately $141.5 million . +Treasury Stock +On October 25, 2018, November 1, 2017, and October 27, 2016, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2018, 2017 and 2016, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2018 , 2017 and 2016 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2018 , the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling and fixed price for the swaps. Each contract is set to expire at varying times during 2019 and 2020. +The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2018 . +Notional Quantity (Bbl or MMBtu) +Weighted Average Price Floor ($/Bbl or +$/MMBtu) +Weighted Average Price Ceiling ($/Bbl or +$/MMBtu) +Fair Value of Asset (Liability) +(thousands) +Commodity +Calculation Period +Oil +01/01/2019 - 12/31/2019 +3,720,000 +$ +53.55 +$ +72.22 +$ +31,531 +Natural Gas +01/01/2019 - 12/31/2019 +2,400,000 +$ +2.50 +$ +3.80 +164 +Total open costless collar contracts +$ +31,695 +The following is a summary of the Company’s open three-way costless collar contracts for oil at December 31, 2018 . Open three-way costless collars consist of a long put (the floor), a short call (the ceiling) and a long call that limits losses on the upside. +Commodity +Calculation Period +Notional Quantity (Bbl) +Weighted Average Price Floor ($/Bbl) +Weighted Average Price, Short Call ($/Bbl) +Weighted Average Price, Long Call ($/Bbl) +Fair Value of Asset (Liability) (thousands) +Oil +01/01/2019 - 12/31/2019 +1,320,000 +$ +60.00 +$ +75.00 +$ +78.85 +$ +18,114 +Natural Gas +01/01/2019 - 12/31/2019 +2.50 +4,800,000 +$ +2.50 +$ +3.00 +3.24 +120 +120 +Total open three-way costless collar contracts +$ +18,234 +The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2018 . +Commodity +Calculation Period +Notional Quantity (Bbl or Gal) +Fixed Price +($/Bbl or $/Gal) +Fair Value of Asset (Liability) +(thousands) +Oil Basis Swaps +01/01/2020 - 12/31/2020 +1,200,000 +$ +(0.15 +) +$ +(83 +) +Total open swap contracts +$ +(83 +) +At December 31, 2018 , the Company had an aggregate asset value for open derivative financial instruments of $49.8 million . +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2018 and December 31, 2017 (in thousands). +Derivative Instruments +Gross amounts recognized +Gross amounts netted in the consolidated balance sheets +Net amounts presented in the consolidated balance sheets +December 31, 2018 +Current assets +$ +53,136 +$ +(3,207 +) +$ +49,929 +Long-term liabilities +(83 +) +— +(83 +) +Total +$ +53,053 +$ +(3,207 +) +$ +49,846 +December 31, 2017 +Current assets +$ +131,092 +$ +(129,902 +) +$ +1,190 +Current liabilities +(146,331 +) +129,902 +(16,429 +) +Total +$ +(15,239 +) +$ +— +$ +(15,239 +) +The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. +Year Ended December 31, +Type of Instrument +Location in Statement of Operations +2018 +2017 +2016 +Derivative Instrument +Oil +Revenues: Realized gain (loss) on derivatives +$ +3,741 +$ +(3,657 +) +$ +5,851 +Natural Gas +Revenues: Realized (loss) gain on derivatives +(1,407 +) +(608 +) +3,435 +NGLs +Revenues: Realized loss on derivatives +— +(56 +) +— +Realized gain (loss) on derivatives +2,334 +(4,321 +) +9,286 +Oil +Revenues: Unrealized gain (loss) on derivatives +65,991 +2,638 +(18,969 +) +Natural Gas +Revenues: Unrealized (loss) gain on derivatives +(906 +) +7,077 +(22,269 +) +Unrealized gain (loss) on derivatives +65,085 +9,715 +(41,238 +) +Total +$ +67,419 +$ +5,394 +$ +(31,952 +) +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 12 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 +Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 +Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 +Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2018 and 2017 (in thousands). +Fair Value Measurements at +December 31, 2018 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil derivatives and basis swaps +$ +— +$ +49,562 +$ +— +$ +49,562 +Natural gas derivatives +— +284 +— +284 +Total +$ +— +$ +49,846 +$ +— +$ +49,846 +Fair Value Measurements at +December 31, 2017 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil derivatives and basis swaps +$ +— +$ +(16,429 +) +$ +— +$ +(16,429 +) +Natural gas derivatives +— +1,190 +— +1,190 +Total +$ +— +$ +(15,239 +) +$ +— +$ +(15,239 +) +Additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified at Level 2 in the fair value hierarchy. +Other Fair Value Measurements +At December 31, 2018 and 2017 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximate their fair values due to their short-term maturities. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 12 — FAIR VALUE MEASUREMENTS — Continued +At December 31, 2018 , the carrying values of the borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2018 and 2017 , the fair value of the Notes and the 2023 Notes was $968.9 million and $614.1 million , respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2018 and 2017 . +NOTE 13 — COMMITMENTS AND CONTINGENCIES +Office Lease +The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026 . The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease. +From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties. +The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2018 (in thousands). +Year Ending December 31, +Amount +2019 +$ +3,091 +2020 +3,914 +2021 +3,877 +2022 +4,009 +2023 +4,141 +Thereafter +9,921 +Total +$ +28,953 +Rent expense, including fees for operating expenses and consumption of electricity, was $2.7 million , $2.6 million and $2.9 million for 2018 , 2017 and 2016 , respectively. +Processing, Transportation and Salt Water Disposal Commitments +Delaware Basin — Loving County, Texas Natural Gas Processing +In late 2015, the Company entered into a 15 -year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2018 , the total deficiency fee required to be paid would be approximately $7.6 million . In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating that year’s natural gas deficiency. The Company paid approximately $15.4 million and $14.4 million in processing and gathering fees under this agreement during the years ended December 31, 2018 and 2017 , respectively. The Company can elect to either sell +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued +the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants. +Delaware Basin — Eddy County, New Mexico Natural Gas Transportation +In late 2017, the Company entered into an 18 -year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this agreement, if the Company does not meet the volume commitment for transportation in a contract year, the Company will owe the fees to transport the committed volume whether or not the committed volume is utilized. The minimum contractual obligation at December 31, 2018 was approximately $20.1 million . The Company paid approximately $3.3 million and $0.2 million in transportation fees, which included no deficiency fees, under this agreement during the years ended December 31, 2018 and 2017, respectively. +In late 2017, the Company also entered into a fixed-fee NGL transportation and fractionation agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant. The Company is committed to deliver a minimum volume of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed in 2020. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company does not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum volume of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven -year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum obligation during the seven -year period would be approximately $132.3 million . +In April 2018, the Company entered into a short-term natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this short-term agreement, the Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation under this short-term contract at December 31, 2018 was approximately $2.7 million . This short-term agreement ends on September 30, 2019. The Company paid approximately $1.9 million in transportation fees under this agreement during the year ended December 31, 2018 . +In April 2018, the Company also entered into a 16 -year, fixed-fee natural gas transportation agreement that begins on October 1, 2019, whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation at December 31, 2018 was approximately $56.8 million . +In May 2018, the Company also entered into a 10 -year, fixed-fee natural gas sales agreement whereby the Company committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date of such pipeline, which is expected to be operational in late 2019. If the Company does not meet the volume commitment specified in the natural gas sales agreement, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum contractual obligation at December 31, 2018 was approximately $200.6 million . +Delaware Basin — San Mateo +In February 2017, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements with subsidiaries of San Mateo. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15 -year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at December 31, 2018 was approximately $221.1 million . +During the first quarter of 2018, a subsidiary of San Mateo entered into agreements for additional field compression and an amine gas treatment unit to maximize the operation of the Black River Processing Plant. Since inception, San Mateo’s +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued +commitments under these agreements totaled $24.9 million . The subsidiary of San Mateo paid approximately $21.3 million under these agreements during the year ended December 31, 2018 . As of December 31, 2018 , the remaining obligations under these agreements were $3.6 million , which are expected to be paid during 2019. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $28.4 million at December 31, 2018 . +At December 31, 2018 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $24.3 million at December 31, 2018 . The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 14 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2018 and 2017 (in thousands). +December 31, +2018 +2017 +Accrued evaluated and unproved and unevaluated property costs +$ +86,318 +$ +105,347 +Accrued midstream properties costs +16,808 +14,823 +Accrued lease operating expenses +12,705 +12,611 +Accrued interest on debt +22,448 +8,345 +Accrued asset retirement obligations +1,350 +1,176 +Accrued partners’ share of joint interest charges +17,037 +27,628 +Other +14,189 +4,418 +Total accrued liabilities +$ +170,855 +$ +174,348 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2018, 2017 and 2016 (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Cash paid for income taxes +$ +— +$ +— +$ +2,895 +Cash paid for interest expense, net of amounts capitalized +$ +29,474 +$ +32,760 +$ +27,464 +Increase in asset retirement obligations related to mineral properties +$ +2,614 +$ +4,385 +$ +3,817 +Increase (decrease) in asset retirement obligations related to midstream properties +$ +686 +$ +(60 +) +$ +222 +(Decrease) increase in liabilities for oil and natural gas properties capital expenditures +$ +(16,802 +) +$ +48,929 +$ +1,775 +Increase (decrease) in liabilities for midstream properties capital expenditures +$ +2,499 +$ +(955 +) +$ +(588 +) +Issuance of restricted stock units for director and advisor services +$ +— +$ +— +$ +992 +Stock-based compensation (benefit) expense recognized as liability +$ +(1,069 +) +$ +362 +$ +569 +(Decrease) increase in liabilities for accrued cost to issue equity +$ +— +$ +(343 +) +$ +343 +Increase in liabilities for accrued cost to issue debt +$ +232 +$ +— +$ +— +Transfer of inventory from (to) oil and natural gas properties +$ +409 +$ +(374 +) +$ +395 +Transfer of inventory to midstream and other property and equipment +$ +— +$ +(317 +) +$ +— +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Cash +$ +64,545 +$ +96,505 +$ +212,884 +Restricted cash +19,439 +5,977 +1,258 +Total cash and restricted cash +$ +83,984 +$ +102,482 +$ +214,142 +NOTE 15 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 15 — SEGMENT INFORMATION — Continued +support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 5). +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2018 +Oil and natural gas revenues +$ +794,261 +$ +6,439 +$ +— +$ +— +$ +800,700 +Midstream services revenues +— +86,737 +— +(64,817 +) +21,920 +Sales of purchased natural gas +902 +6,169 +— +— +7,071 +Lease bonus - mineral acreage +2,489 +— +— +— +2,489 +Realized gain on derivatives +2,334 +— +— +— +2,334 +Unrealized gain on derivatives +65,085 +— +— +— +65,085 +Expenses (1) +487,539 +44,098 +69,508 +(64,817 +) +536,328 +Operating income (loss) (2) +$ +377,532 +$ +55,247 +$ +(69,508 +) +$ +— +$ +363,271 +Total assets +$ +2,910,326 +$ +439,953 +$ +105,239 +$ +— +$ +3,455,518 +Capital expenditures (3) +$ +1,335,690 +$ +166,407 +$ +2,562 +$ +— +$ +1,504,659 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $252.3 million and $10.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.4 million . +(2) +Includes $25.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +Includes $656.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $80.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 15 — SEGMENT INFORMATION — Continued +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2017 +Oil and natural gas revenues +$ +525,862 +$ +2,822 +$ +— +$ +— +$ +528,684 +Midstream services revenues +— +47,037 +— +(36,839 +) +10,198 +Realized loss on derivatives +(4,321 +) +— +— +— +(4,321 +) +Unrealized gain on derivatives +9,715 +— +— +— +9,715 +Expenses (1) +333,923 +23,420 +62,931 +(36,839 +) +383,435 +Operating income (loss) (2) +$ +197,333 +$ +26,439 +$ +(62,931 +) +$ +— +$ +160,841 +Total assets +$ +1,768,393 +$ +257,871 +$ +119,426 +$ +— +$ +2,145,690 +Capital expenditures (3) +$ +753,157 +$ +114,113 +$ +5,688 +$ +— +$ +872,958 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million . +(2) +Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2016 +Oil and natural gas revenues +$ +289,512 +$ +1,644 +$ +— +$ +— +$ +291,156 +Midstream services revenues +— +18,982 +— +(13,764 +) +5,218 +Realized gain on derivatives +9,286 +— +— +— +9,286 +Unrealized loss on derivatives +(41,238 +) +— +— +— +(41,238 +) +Expenses (1) +391,098 +8,254 +56,001 +(13,764 +) +441,589 +Operating (loss) income (2) +$ +(133,538 +) +$ +12,372 +$ +(56,001 +) +$ +— +$ +(177,167 +) +Total assets +$ +1,098,525 +$ +140,459 +$ +225,681 +$ +— +$ +1,464,665 +Capital expenditures +$ +379,881 +$ +67,566 +$ +6,913 +$ +— +$ +454,360 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment. +(2) +Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 16 — SUBSIDIARY GUARANTORS +The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2018 , the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes. +The following presents condensed consolidating financial information of the issuer (Matador), the Non-Guarantor Subsidiaries, the Guarantor Subsidiaries and all entities on a consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. +Condensed Consolidating Balance Sheet +December 31, 2018 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +ASSETS +Intercompany receivable +$ +1,244,405 +$ +29,816 +$ +— +$ +(1,274,221 +) +$ +— +Current assets +4,109 +34,027 +267,549 +— +305,685 +Net property and equipment +— +379,052 +2,743,812 +— +3,122,864 +Investment in subsidiaries +1,490,401 +— +95,346 +(1,585,747 +) +— +Long-term assets +23,897 +1,479 +11,095 +(9,502 +) +26,969 +Total assets +$ +2,762,812 +$ +444,374 +$ +3,117,802 +$ +(2,869,470 +) +$ +3,455,518 +LIABILITIES AND EQUITY +Intercompany payable +$ +— +$ +— +$ +1,274,221 +$ +(1,274,221 +) +$ +— +Current liabilities +22,874 +27,988 +279,884 +(724 +) +330,022 +Senior unsecured notes payable +1,037,837 +— +— +1,037,837 +Other long-term liabilities +13,221 +230,263 +73,296 +(8,778 +) +308,002 +Total equity attributable to Matador Resources Company +1,688,880 +95,346 +1,490,401 +(1,585,747 +) +1,688,880 +Non-controlling interest in subsidiaries +— +90,777 +— +— +90,777 +Total liabilities and equity +$ +2,762,812 +$ +444,374 +$ +3,117,802 +$ +(2,869,470 +) +$ +3,455,518 +Condensed Consolidating Balance Sheet +December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +ASSETS +Intercompany receivable +$ +585,109 +$ +2,912 +$ +— +$ +(588,021 +) +$ +— +Third-party current assets +2,240 +9,334 +245,596 +— +257,170 +Net property and equipment +— +223,178 +1,658,278 +— +1,881,456 +Investment in subsidiaries +1,147,295 +— +111,077 +(1,258,372 +) +— +Third-party long-term assets +6,425 +— +3,642 +(3,003 +) +7,064 +Total assets +$ +1,741,069 +$ +235,424 +$ +2,018,593 +$ +(1,849,396 +) +$ +2,145,690 +LIABILITIES AND EQUITY +Intercompany payable +$ +— +$ +— +$ +588,021 +$ +(588,021 +) +$ +— +Third-party current liabilities +8,847 +19,891 +254,142 +(274 +) +282,606 +Senior unsecured notes payable +574,073 +— +— +— +574,073 +Other third-party long-term liabilities +1,593 +3,466 +29,135 +(2,729 +) +31,465 +Total equity attributable to Matador Resources Company +1,156,556 +111,077 +1,147,295 +(1,258,372 +) +1,156,556 +Non-controlling interest in subsidiaries +— +100,990 +— +— +100,990 +Total liabilities and equity +$ +1,741,069 +$ +235,424 +$ +2,018,593 +$ +(1,849,396 +) +$ +2,145,690 +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 16 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2018 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +98,665 +$ +865,725 +$ +(64,791 +) +$ +899,599 +Total expenses +4,935 +46,236 +549,948 +(64,791 +) +536,328 +Operating (loss) income +(4,935 +) +52,429 +315,777 +— +363,271 +Net loss on asset sales and inventory impairment +— +— +(196 +) +— +(196 +) +Interest expense +(40,994 +) +(333 +) +— +— +(41,327 +) +Prepayment penalty on extinguishment of debt +(31,226 +) +— +— +— +(31,226 +) +Other income +565 +62 +924 +— +1,551 +Earnings in subsidiaries +343,106 +— +26,601 +(369,707 +) +— +Income before income taxes +266,516 +52,158 +343,106 +(369,707 +) +292,073 +Total income tax benefit +(7,691 +) +— +— +— +(7,691 +) +Net income attributable to non-controlling interest in subsidiaries +— +(25,557 +) +— +— +(25,557 +) +Net income attributable to Matador Resources Company shareholders +$ +274,207 +$ +26,601 +$ +343,106 +$ +(369,707 +) +$ +274,207 +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +47,883 +$ +531,508 +$ +(35,115 +) +$ +544,276 +Total expenses +5,610 +21,260 +391,680 +(35,115 +) +383,435 +Operating (loss) income +(5,610 +) +26,623 +139,828 +— +160,841 +Net gain on asset sales and inventory impairment +— +— +23 +— +23 +Interest expense +(34,565 +) +— +— +— +(34,565 +) +Other income +27 +37 +3,487 +— +3,551 +Earnings in subsidiaries +157,589 +— +14,251 +(171,840 +) +— +Income before income taxes +117,441 +26,660 +157,589 +(171,840 +) +129,850 +Total income tax (benefit) provision +(8,426 +) +269 +— +— +(8,157 +) +Net income attributable to non-controlling interest in subsidiaries +— +(12,140 +) +— +— +(12,140 +) +Net income attributable to Matador Resources Company shareholders +$ +125,867 +$ +14,251 +$ +157,589 +$ +(171,840 +) +$ +125,867 +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 16 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2016 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +17,302 +$ +257,828 +$ +(10,708 +) +$ +264,422 +Total expenses +5,319 +7,031 +439,947 +(10,708 +) +441,589 +Operating (loss) income +(5,319 +) +10,271 +(182,119 +) +— +(177,167 +) +Net gain on asset sales and inventory impairment +— +— +107,277 +— +107,277 +Interest expense +(28,199 +) +— +— +— +(28,199 +) +Other expense +— +— +(4 +) +— +(4 +) +(Loss) earnings in subsidiaries +(64,349 +) +— +9,810 +54,539 +— +(Loss) income before income taxes +(97,867 +) +10,271 +(65,036 +) +54,539 +(98,093 +) +Total income tax (benefit) provision +(446 +) +97 +(687 +) +— +(1,036 +) +Net income attributable to non-controlling interest in subsidiaries +— +(364 +) +— +— +(364 +) +Net (loss) income attributable to Matador Resources Company shareholders +$ +(97,421 +) +$ +9,810 +$ +(64,349 +) +$ +54,539 +$ +(97,421 +) +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2018 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +(657,860 +) +$ +35,119 +$ +1,231,264 +$ +— +$ +608,523 +Net cash used in investing activities +— +(162,147 +) +(1,310,776 +) +(42,330 +) +(1,515,253 +) +Net cash provided by financing activities +658,030 +140,205 +47,667 +42,330 +888,232 +Increase (decrease) in cash and restricted cash +170 +13,177 +(31,845 +) +— +(18,498 +) +Cash and restricted cash at beginning of year +286 +5,663 +96,533 +— +102,482 +Cash and restricted cash at end of year +$ +456 +$ +18,840 +$ +64,688 +$ +— +$ +83,984 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +(307,982 +) +$ +21,308 +$ +585,799 +$ +— +$ +299,125 +Net cash provided by (used in) investing activities +33 +(114,852 +) +(597,870 +) +(106,595 +) +(819,284 +) +Net cash provided by (used in) financing activities +208,440 +96,307 +(2,843 +) +106,595 +408,499 +Decrease in cash and restricted cash +(99,509 +) +2,763 +(14,914 +) +— +(111,660 +) +Cash and restricted cash at beginning of year +99,795 +2,900 +111,447 +— +214,142 +Cash and restricted cash at end of year +$ +286 +$ +5,663 +$ +96,533 +$ +— +$ +102,482 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2016 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +(45,215 +) +$ +6,694 +$ +172,607 +$ +— +$ +134,086 +Net cash used in investing activities +(324,724 +) +(64,999 +) +(443,817 +) +384,801 +(448,739 +) +Net cash provided by financing activities +469,654 +60,110 +322,743 +(384,801 +) +467,706 +Increase in cash and restricted cash +99,715 +1,805 +51,533 +— +153,053 +Cash and restricted cash at beginning of year +80 +1,095 +59,914 +— +61,089 +Cash and restricted cash at end of year +$ +99,795 +$ +2,900 +$ +111,447 +$ +— +$ +214,142 +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2018, 2017 and 2016 +NOTE 17 — SUBSEQUENT EVENTS +On February 25, 2019, the Company announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with a subsidiary of Five Point designed to expand the Company’s midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by the Company and 49% by Five Point. In addition, Five Point has committed to pay $125 million of the first $150 million of capital expenditures incurred by San Mateo II to develop facilities in the Stebbins area and the Stateline asset area. The Company has the ability to earn up to $150 million in deferred performance incentives over the next five years , plus additional performance incentives for securing volumes from third-party customers. +In connection with the formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Stebbins area and the Stateline asset area pursuant to 15 -year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal (collectively, the “San Mateo II Operational Agreements”). San Mateo II will provide the Company with firm service under each of the San Mateo II Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the San Mateo II Operational Agreements at inception was approximately $363.8 million and begins in 2020. +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2018, 2017 and 2016 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2018, 2017 and 2016 (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Property acquisition costs +Proved +$ +4,788 +$ +45,270 +$ +— +Unproved and unevaluated +633,502 +214,662 +108,206 +Exploration costs +229,974 +167,213 +113,562 +Development costs +467,426 +326,012 +158,113 +Total costs incurred (1) +$ +1,335,690 +$ +753,157 +$ +379,881 +__________________ +(1) +Excludes midstream-related development and corporate costs of approximately $169.0 million, $119.8 million and $74.5 million for the years ended December 31, 2018, 2017 and 2016 , respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2018, 2017 and 2016 , most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the years ended December 31, 2018 , 2017 and 2016 , the Company capitalized $17.7 million, $1.8 million and $3.6 million, respectively, of geological and geophysical costs, which are included as exploration costs in the table above. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $4.0 million , $4.8 million and $4.4 million for the years ended December 31, 2018, 2017 and 2016 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $28.3 million , $23.1 million and $15.7 million of these internal costs for the years ended December 31, 2018 , 2017 and 2016 , respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $8.8 million , $7.3 million and $3.7 million of its interest expense for the years ended December 31, 2018 , 2017 and 2016 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2018, 2017 and 2016 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2018, 2017 and 2016 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2018 , these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2018, 2017 and 2016 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2015 +45,644 +236,901 +85,127 +Revisions of prior estimates +(6,440 +) +(28,481 +) +(11,187 +) +Extensions and discoveries +22,869 +114,730 +41,992 +Production +(5,096 +) +(30,501 +) +(10,180 +) +Total at December 31, 2016 +56,977 +292,649 +105,752 +Revisions of prior estimates +3,847 +34,395 +9,580 +Purchases of minerals-in-place +5,257 +7,348 +6,482 +Extensions and discoveries +28,513 +99,935 +45,169 +Production +(7,851 +) +(38,163 +) +(14,212 +) +Total at December 31, 2017 +86,743 +396,164 +152,771 +Revisions of prior estimates +5,908 +32,497 +11,326 +Purchases of minerals-in-place +446 +900 +596 +Extensions and discoveries +41,445 +169,224 +69,646 +Production +(11,141 +) +(47,311 +) +(19,026 +) +Total at December 31, 2018 +123,401 +551,474 +215,313 +Proved Developed Reserves +December 31, 2015 +17,129 +101,447 +34,037 +December 31, 2016 +22,604 +126,759 +43,731 +December 31, 2017 +36,966 +190,109 +68,651 +December 31, 2018 +53,223 +246,229 +94,261 +Proved Undeveloped Reserves +December 31, 2015 +28,515 +135,454 +51,090 +December 31, 2016 +34,373 +165,890 +62,021 +December 31, 2017 +49,777 +206,055 +84,120 +December 31, 2018 +70,178 +305,245 +121,052 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2018, 2017 and 2016 . +The Company’s proved oil and natural gas reserves increased to 215,313 MBOE at December 31, 2018 from 152,771 MBOE at December 31, 2017 . The Company’s proved oil and natural gas reserves increased by 81,568 MBOE and the Company produced 19,026 MBOE during the year ended December 31, 2018 , resulting in a net increase of 62,542 MBOE. An increase of 69,646 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 11,326 MBOE during 2018 as a result of revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves in 2018 , as compared to 2017 . The Company also added 596 MBOE in proved oil and natural gas reserves in 2018 as a result of purchases of minerals-in-place in the Delaware Basin. The Company’s proved developed oil and natural gas reserves increased to 94,261 MBOE at December 31, 2018 from 68,651 MBOE at December 31, 2017 , primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2018 , the Company’s proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 44% proved developed and approximately 56% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 152,771 MBOE at December 31, 2017 from 105,752 MBOE at December 31, 2016. The Company’s proved oil and natural gas reserves increased by 61,231 MBOE and the Company produced 14,212 MBOE during the year ended December 31, 2017, resulting in a net increase of 47,019 MBOE. An +F-43 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2018, 2017 and 2016 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +increase of 45,169 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 9,580 MBOE during 2017 as a result of revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves in 2017, as compared to 2016. The Company also added 6,482 MBOE in proved oil and natural gas reserves in 2017 as a result of purchases of minerals-in-place in the Delaware Basin. The Company’s proved developed oil and natural gas reserves increased to 68,651 MBOE at December 31, 2017 from 43,731 MBOE at December 31, 2016, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2017, the Company’s proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 105,752 MBOE at December 31, 2016 from 85,127 MBOE at December 31, 2015. The Company’s proved oil and natural gas reserves increased by 30,805 MBOE and the Company produced 10,180 MBOE during the year ended December 31, 2016, resulting in a net increase of 20,625 MBOE. An increase of 41,992 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves decreased by 11,187 MBOE during 2016 as a result of the reclassification of proved undeveloped reserves to contingent resources, primarily due to the decline in weighted average commodity prices used to estimate proved reserves during 2016, as compared to 2015. The Company’s proved developed oil and natural gas reserves increased to 43,731 MBOE at December 31, 2016 from 34,037 MBOE at December 31, 2015, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2016, the Company’s proved reserves were made up of approximately 54% oil and 46% natural gas and were approximately 41% proved developed and approximately 59% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2018 , the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. For the period from January through December 2017 , the comparable average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , the comparable average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-44 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2018, 2017 and 2016 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2018, 2017 and 2016 (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Future cash inflows +$ +8,822,004 +$ +5,249,116 +$ +2,684,877 +Future production costs +(2,713,043 +) +(1,759,495 +) +(927,725 +) +Future development costs +(1,384,916 +) +(1,029,105 +) +(630,280 +) +Future income tax expense +(710,222 +) +(228,622 +) +(24,742 +) +Future net cash flows +4,013,823 +2,231,894 +1,102,130 +10% annual discount for estimated timing of cash flows +(1,763,210 +) +(973,248 +) +(527,087 +) +Standardized measure of discounted future net cash flows +$ +2,250,613 +$ +1,258,646 +$ +575,043 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2018, 2017 and 2016 (in thousands). +Year Ended December 31, +2018 +2017 +2016 +Balance, beginning of period +$ +1,258,646 +$ +575,043 +$ +529,181 +Net change in sales and transfer prices and in production (lifting) costs related to future production +574,381 +374,370 +(92,477 +) +Changes in estimated future development costs +(347,038 +) +(298,504 +) +(74,142 +) +Sales and transfers of oil and natural gas produced during the period +(631,596 +) +(403,095 +) +(191,908 +) +Purchases of reserves in place +9,227 +97,225 +— +Net change due to extensions and discoveries +1,078,935 +677,681 +360,033 +Net change due to revisions in estimates of reserves quantities +175,440 +143,749 +(95,917 +) +Previously estimated development costs incurred during the period +279,799 +151,974 +84,519 +Accretion of discount +103,085 +54,623 +51,779 +Other +3,600 +(3,929 +) +(1,962 +) +Net change in income taxes +(253,866 +) +(110,491 +) +5,937 +Standardized measure of discounted future net cash flows +$ +2,250,613 +$ +1,258,646 +$ +575,043 +F-45 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2018, 2017 and 2016 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2018 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2018 +Oil and natural gas revenues +$ +193,445 +$ +216,282 +$ +209,019 +$ +181,954 +Third-party midstream services revenues +8,636 +6,809 +3,407 +3,068 +Sales of purchased gas +7,071 +— +— +— +Lease bonus - mineral acreage +2,489 +— +— +— +Realized gain (loss) on derivatives +3,656 +5,424 +(2,488 +) +(4,258 +) +Unrealized gain (loss) on derivatives +74,577 +(21,337 +) +1,429 +10,416 +Expenses +141,811 +139,325 +137,374 +117,818 +Other expense +(11,666 +) +(42,738 +) +(8,356 +) +(8,438 +) +Income before income taxes +136,397 +25,115 +65,637 +64,924 +Income tax benefit +(7,691 +) +— +— +— +Net income +144,088 +25,115 +65,637 +64,924 +Net income attributable to non-controlling interest in subsidiaries +(7,375 +) +(7,321 +) +(5,831 +) +(5,030 +) +Net income attributable to +Matador Resources Company shareholders +$ +136,713 +$ +17,794 +$ +59,806 +$ +59,894 +Earnings per common share +Basic +$ +1.18 +$ +0.15 +$ +0.53 +$ +0.55 +Diluted +$ +1.17 +$ +0.15 +$ +0.53 +$ +0.55 +The following table presents selected unaudited quarterly financial information for 2017 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2017 +Oil and natural gas revenues +$ +165,125 +$ +134,948 +$ +113,764 +$ +114,847 +Third-party midstream services revenues +3,326 +3,218 +2,099 +1,555 +Realized (loss) gain on derivatives +(3,145 +) +485 +558 +(2,219 +) +Unrealized (loss) gain on derivatives +(11,734 +) +(12,372 +) +13,190 +20,631 +Expenses +112,547 +99,730 +90,622 +80,536 +Other expense +(6,741 +) +(8,570 +) +(7,302 +) +(8,378 +) +Income before income taxes +34,284 +17,979 +31,687 +45,900 +Income tax benefit +(8,157 +) +— +— +— +Net income +42,441 +17,979 +31,687 +45,900 +Net income attributable to non-controlling interest in subsidiaries +(4,106 +) +(2,940 +) +(3,178 +) +(1,916 +) +Net income attributable to +Matador Resources Company shareholders +$ +38,335 +$ +15,039 +$ +28,509 +$ +43,984 +Earnings per common share +Basic +$ +0.36 +$ +0.15 +$ +0.28 +$ +0.44 +Diluted +$ +0.35 +$ +0.15 +$ +0.28 +$ +0.44 +F-46 \ No newline at end of file diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/filing_metadata.csv b/raw/filings/0001520006/2018/0001520006-19-000048/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..4abbe72cd05db74624fcf4465ebc664f5e1c9791 --- /dev/null +++ b/raw/filings/0001520006/2018/0001520006-19-000048/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2019-03-01,2018-12-31,2019-03-02T03:00:43.000Z,0001520006-19-000048,a20181231mtdr10-k.htm,10-K,15251306,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000152000619000048/a20181231mtdr10-k.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000619000048/,2018,2018,1 diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/item1.txt b/raw/filings/0001520006/2018/0001520006-19-000048/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..0688ee1e50d502513e073c8dbf49438bc1b60602 --- /dev/null +++ b/raw/filings/0001520006/2018/0001520006-19-000048/item1.txt @@ -0,0 +1,1321 @@ +Item 1. Business. +In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2018 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also continued to increase our leasehold and minerals position in the Delaware Basin, in particular through the BLM Acquisition (as defined below). In addition, we concluded several important financing transactions in 2018 , including the May 2018 public +2 +Table of Contents +offering of 7,000,000 shares of our common stock, the refinancing and issuance of senior unsecured notes and two increases in the borrowing base under our Credit Agreement (as defined below). San Mateo also achieved several important milestones in 2018, including the completion and successful start-up of the expansion of the Black River Processing Plant (as defined below), the formation of a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains All American Pipeline, L.P. (“Plains”) to gather and transport crude oil for us and third-party customers in and around the Rustler Breaks asset area, the completion and start-up of the Rustler Breaks Oil Pipeline System (as defined below), the addition of several significant third-party customers for salt water gathering and disposal and natural gas gathering and processing and the closing of the San Mateo Credit Facility (as defined below). These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2018 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2018 , we achieved record oil, natural gas and average daily oil equivalent production. In 2018 , we produced 11.1 million Bbl of oil, an increase of 42% , as compared to 7.9 million Bbl of oil produced in 2017 . We also produced 47.3 Bcf of natural gas, an increase of 24% from 38.2 Bcf of natural gas produced in 2017 . Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, an increase of 34% , as compared to 38,936 BOE per day, including 21,510 Bbl of oil per day and 104.6 MMcf of natural gas per day, for the year ended December 31, 2017 . The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2018 , which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Oil production comprised 59% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2018 , as compared to 55% for the year ended December 31, 2017 . +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2018 , our estimated total proved oil and natural gas reserves were 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, an increase of 41% from 152.8 million BOE, including 86.7 million Bbl of oil and 396.2 Bcf of natural gas, at December 31, 2017 . The associated Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 79% and 93% to $2.25 billion and $2.58 billion , respectively, at December 31, 2018 , from $1.26 billion and $1.33 billion , respectively, at December 31, 2017 , primarily as a result of our ongoing delineation and development drilling activities in the Delaware Basin during 2018 and higher weighted average oil and natural gas prices used to estimate proved reserves. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 42% to 123.4 million Bbl at December 31, 2018 from 86.7 million Bbl at December 31, 2017 . Our proved natural gas reserves increased 39% to 551.5 Bcf at December 31, 2018 from 396.2 Bcf at December 31, 2017 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2018 . +At December 31, 2018 , proved developed reserves included 53.2 million Bbl of oil and 246.2 Bcf of natural gas, and proved undeveloped reserves included 70.2 million Bbl of oil and 305.2 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 44% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2018 . Proved developed reserves and proved oil reserves comprised 45% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2017 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past five years. We expect the Delaware Basin will continue to be our primary area of focus in 2019 . +3 +Table of Contents +We completed and began producing oil and natural gas from 141 gross (73.8 net) wells in the Delaware Basin in 2018 , including 82 gross (66.8 net) operated and 59 gross (7.0 net) non-operated wells. We also added to and upgraded our acreage position in the Delaware Basin during 2018 . As a result, at December 31, 2018 , our total acreage position in the Delaware Basin had increased to approximately 222,200 gross ( 132,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on our seven main asset areas—the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 54% to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 , as compared to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 MMcf of natural gas per day ( 66% of total natural gas production), in 2017 . We expect our Delaware Basin production to increase in 2019 as we continue the delineation and development of these asset areas. +Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2018 included: +• +in our Rustler Breaks asset area, the results from the David Edelstein State Com 12&11-24S-27E RB #203H well, our first operated two-mile horizontal well, the performance of our Wolfcamp A-XY completions moving to the northwest region of the asset area, positive tests of the Second Bone Spring formation and the continued delineation and development of previously tested horizons; +• +in our Wolf asset area, the results from several wells with longer laterals (greater than one mile) drilled and completed in the Wolfcamp A-XY interval in the southern portion of the asset area; +• +in our Jackson Trust asset area, the continued development of the Wolfcamp A-Lower interval; +• +in our Arrowhead and Ranger asset areas, the results from our Second and Third Bone Spring completions, particularly in the SST and Stebbins acreage blocks in the Arrowhead asset area, and results from the recently completed Verna Rae Federal #204H well in the Ranger asset area, whose 24-hour initial potential (“IP”) test results and subsequent well performance demonstrate the potential prospectivity of the Wolfcamp formation moving north in the Delaware Basin; +• +in our Antelope Ridge asset area, the testing of six distinct intervals during 2018, including the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower; and +• +the significant progress made in our midstream operations, including (i) the completion and successful startup of the expansion of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”) to a designed inlet capacity of 260 MMcf of natural gas per day, (ii) the completion of a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP, (iii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas, (iv) the entrance into a strategic relationship with Plains to gather and transport crude oil in the Rustler Breaks asset area, (v) placing into service crude oil gathering and transportation systems in the Wolf and Rustler Breaks asset areas, (vi) entering into long-term agreements with significant producers in Eddy County, New Mexico relating to the gathering and disposal of one such producer’s salt water and the gathering and processing of another such producer’s natural gas production and (vii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks asset area, significantly increasing San Mateo’s salt water disposal capacity. +We also completed and began producing oil and natural gas from four gross (1.5 net) wells in the Eagle Ford shale in South Texas in 2018 , including one gross (1.0 net) operated and three gross (0.5 net) non-operated wells. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2018 , although we did participate in the drilling and completion of eight gross (0.2 net) non-operated Haynesville shale wells that began producing in 2018 . +Financing Arrangements +We concluded several important financing transactions in 2018 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• +the completion of a public offering of 7,000,000 shares of our common stock, whereby we received net proceeds of approximately $226.4 million; +• +a series of transactions whereby we (i) issued $1.05 billion aggregate principal amount of senior notes and received net proceeds of $1.04 billion, (ii) redeemed $575.0 million aggregate principal amount of senior notes, (iii) improved the coupon rate on our senior notes outstanding to 5.875% from 6.875% and (iv) extended the maturity date of our senior notes from 2023 to 2026; +4 +Table of Contents +• +the amendment of our third amended and restated credit agreement (the “Credit Agreement”) to, among other items, (i) increase the maximum facility amount to $1.5 billion, (ii) increase the borrowing base to $850.0 million, (iii) increase the elected borrowing commitment to $500.0 million, (iv) extend the maturity to October 31, 2023, (v) reduce borrowing rates by 0.25% per annum and (vi) set the maximum leverage ratio at 4.00 to 1.00; and +• +San Mateo’s entrance into a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and the cash distribution of $195.0 million, which was distributed 51% to us and 49% to our partner. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional information regarding these financing arrangements. +BLM Acquisition +On September 12, 2018, we announced the successful acquisition of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million, or a weighted average cost of approximately $46,000 per net acre, in the Bureau of Land Management (the “BLM”) New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”). The acquired leasehold acreage includes approximately 2,800 gross and net acres in the Stateline asset area on the Texas/New Mexico border, 4,800 gross and net acres in the Antelope Ridge asset area, 400 gross and net acres in the Arrowhead asset area and 400 gross and net acres in the Twin Lakes asset area. The leases for all tracts covering the BLM Acquisition were issued in the fourth quarter of 2018. +At February 26, 2019 , we were actively pursuing drilling permits on a number of these tracts, including the approximately 2,800 gross and net acres in the Stateline asset area and the approximately 1,200 gross and net acres in the western portion of the Antelope Ridge asset area. We expect to begin drilling operations on these Stateline and western Antelope Ridge properties as early as the fourth quarter of 2019 or the first quarter of 2020. +Midstream Highlights +On January 22, 2018, we announced a strategic relationship between a subsidiary of San Mateo and a subsidiary of Plains to gather and transport crude oil for upstream producers in and around the Rustler Breaks asset area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. San Mateo completed its expanded oil gathering system in the Wolf asset area in Loving County, Texas (the “Wolf Oil Pipeline System”) in May 2018, and, in December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following a successful open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. +In late March 2018, San Mateo completed the expansion of the Black River Processing Plant, adding an incremental designed inlet capacity of 200 MMcf of natural gas per day and bringing the total designed inlet capacity of the Black River Processing Plant to 260 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin, and with the expanded capacity, San Mateo can offer natural gas processing services to other producers as well. +In October 2018, a subsidiary of San Mateo entered into a long-term agreement with a producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including the Company, at December 31, 2018 , San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant. In addition, in June 2018, a subsidiary of San Mateo entered into a long-term agreement with another significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. +2019 Recent Developments +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. As part of this transaction, we dedicated to San Mateo II acreage in the Stebbins area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. In addition, Five Point has committed to pay $125 million of the first $150 million of capital expenditures incurred by San Mateo II to +5 +Table of Contents +develop facilities in the Stebbins area and the Stateline asset area. Five Point has also provided us the opportunity to earn deferred performance incentives of up to $150 million over the next five years as we execute our operational plans in and around the Stebbins area and the Stateline asset area, plus additional performance incentives for securing volumes from third-party customers. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. During 2018 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our asset areas by exploring for and developing more conventional targets as well, although for the year ended December 31, 2018 , essentially all of our efforts were focused on unconventional plays. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2018 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +222,200 +132,000 +630 +290.7 +5,442 +2,472.2 +191,490 +42.3 +45,237 +South Texas: +Eagle Ford (5) +32,000 +28,900 +148 +122.5 +238 +206.9 +12,189 +61.5 +3,158 +Northwest Louisiana/East Texas: +Haynesville +19,600 +12,000 +227 +20.4 +395 +100.2 +10,919 +46.5 +3,417 +Cotton Valley (6) +21,100 +18,600 +79 +53.3 +71 +49.2 +715 +100.0 +316 +Area Total (7) +25,500 +22,800 +306 +73.7 +466 +149.4 +11,634 +49.8 +3,733 +Total +279,700 +183,700 +1,084 +486.9 +6,146 +2,828.5 +215,313 +43.8 +52,128 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2018 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Each location represents a one-mile lateral. At December 31, 2018 , these engineered drilling locations included only 301 gross (147.6 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, in the Delaware Basin, 17 gross (17.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 14 gross (4.9 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2018 . +(5) +Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2018 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2018 , we also were the operator for approximately 94% of our Eagle Ford acreage and approximately 64% of our Haynesville acreage, including +6 +Table of Contents +approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by an affiliate of Chesapeake Energy Corporation. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +As noted above in “— 2018 Highlights—Operational Highlights,” we increased our acreage position in the Delaware Basin during 2018 , and as a result, at December 31, 2018 , our total acreage position in Southeast New Mexico and West Texas was approximately 222,200 gross ( 132,000 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 34,200 gross (17,500 net) acres in our Ranger asset area in Lea County, 60,100 gross (25,700 net) acres in our Arrowhead asset area in Eddy County, 45,300 gross (26,200 net) acres in our Rustler Breaks asset area in Eddy County, 20,500 gross (17,300 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,700 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our recently acquired Stateline asset area in Eddy County and 44,300 gross (31,300 net) acres in our Twin Lakes asset area in Lea County at December 31, 2018 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2018 , our acreage position in the Delaware Basin was approximately 54% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only one vertical operated well and two horizontal operated wells, and the acreage acquired in the BLM Acquisition, which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 73% held by existing production at December 31, 2018 . +During the year ended December 31, 2018 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 141 gross (73.8 net) wells in the Delaware Basin, including 82 gross (66.8 net) operated wells and 59 gross (7.0 net) non-operated wells, throughout our various asset areas. At December 31, 2018 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, Avalon, the First Bone Spring, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2018 . Our average daily oil equivalent production from the Delaware Basin increased approximately 54% to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 , as compared to 29,463 BOE per day ( 76% of total oil equivalent production), including 18,023 Bbl of oil per day ( 84% of total oil production) and 68.6 +7 +Table of Contents +MMcf of natural gas per day ( 66% of total natural gas production), in 2017 . Our average daily oil equivalent production from the Delaware Basin also grew approximately 41% from 34,859 BOE per day in the fourth quarter of 2017 to 49,309 BOE per day in the fourth quarter of 2018 . +At December 31, 2018 , approximately 89% of our estimated total proved oil and natural gas reserves, or 191.5 million BOE, was attributable to the Delaware Basin, including approximately 114.8 million Bbl of oil and 460.0 Bcf of natural gas, a 48% increase, as compared to 129.0 million BOE for the year ended December 31, 2017 . Our Delaware Basin proved reserves at December 31, 2018 comprised approximately 93% of our proved oil reserves and 83% of our proved natural gas reserves, as compared to approximately 89% of our proved oil reserves and 78% of our proved natural gas reserves at December 31, 2017 . +At December 31, 2018 , we had identified 5,442 gross ( 2,472.2 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 3,451 gross (2,278.0 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Each horizontal drilling location assumes a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2018 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico. Our identified well locations presume that these properties may be developed on 80- to 160-acre well spacing and that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible, at December 31, 2018 , the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2018 , these potential future drilling locations included 301 gross (147.6 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, to which we have assigned proved undeveloped reserves. +At December 31, 2018 , we were operating six drilling rigs in the Delaware Basin, and we expect to operate these six rigs in the Delaware Basin throughout 2019, including two rigs in each of the Rustler Breaks and Antelope Ridge asset areas, one rig in the Wolf/Jackson Trust asset areas and one rig in the Ranger/Arrowhead and Twin Lakes asset areas. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 12 months. The other three rigs are on short-term contracts with remaining obligations of six months or less. This affords us the ability to modify our drilling program as we may deem necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2019. +Rustler Breaks Asset Area - Eddy County, New Mexico +We operated two to three drilling rigs in our Rustler Breaks asset area during most of 2018. We completed and turned to sales 83 gross (41.8 net) horizontal wells and two gross (1.5 net) vertical wells in the Rustler Breaks asset area in 2018, including 46 gross (38.0 net) operated and 39 gross (5.3 net) non-operated wells. Most of these wells were completed in the Wolfcamp A-XY or Wolfcamp B-Blair intervals. +One of the key achievements of our drilling and completions program in our Rustler Breaks asset area in 2018 was our first operated two-mile horizontal well—the David Edelstein State Com 12&11-24S-27E RB #203H (Edelstein #203H) well, a Wolfcamp A-XY completion. The Edelstein #203H well tested 2,378 BOE per day (77% oil) during a 24-hour IP test in the third quarter of 2018. +We were pleased in 2018 with the success of our wells drilled in the northwestern portion of our acreage position. For example, the Miss Sue 12-23S-27E RB #201H (Miss Sue #201H) and the Michael Collins 11-23S-27E RB #201H (Michael Collins #201H) wells tested 1,706 BOE per day (76% oil) and 2,125 BOE per day (78% oil), respectively, during 24-hour IP tests. The Joe Coleman 13-23S-27E RB #201H and #203H (Joe Coleman #201H and #203H) wells tested 1,702 BOE per day (80% oil) and 1,831 BOE per day (73% oil), respectively, during 24-hour IP tests. In seven months of production, the Joe Coleman #201H and #203H wells have produced approximately 210,000 BOE (69% oil) and 190,000 BOE (70% oil), respectively. +In addition, the Garrett Fed Com #122H (Garrett #122H) well, a Second Bone Spring completion in the Rustler Breaks asset area, flowed 2,411 BOE per day (84% oil) during a 24-hour IP test. We expect to further delineate the Second Bone Spring formation moving to the northwest in our Rustler Breaks asset area using two-mile laterals beginning in the latter part of 2019 or early 2020. +8 +Table of Contents +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY and Wolfcamp A-Lower formations in 2018. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2018, and we completed and turned to sales 11 gross (8.0 net) operated horizontal wells in these asset areas. Most of these wells were completed in the Wolfcamp A-XY interval. +In the fourth quarter of 2018, we completed and placed on production the Wolf 80-TTT-B33 WF #206H and #208H (Wolf #206H and #208H) wells. These wells tested 2,509 BOE per day (41% oil) and 2,514 BOE per day (39% oil), respectively, during 24-hour IP tests. We attribute these well results to the selection of an improved landing target identified through the use of 3-D seismic data, the longer lateral lengths drilled and completed (5,600 and 6,200 feet, respectively) and an improved stimulation design. +Arrowhead and Ranger Asset Areas - Eddy and Lea Counties, New Mexico +We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2018. We completed and turned to sales 13 gross (7.9 net) horizontal wells in the Arrowhead and Ranger asset areas in 2018, including 10 gross (7.5 net) operated and three gross (0.4 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals. +The SST 6 State #123H and #124H wells, our first two Second Bone Spring wells drilled on the SST leasehold north of the Stebbins acreage in the Arrowhead asset area, tested 2,056 BOE per day (85% oil) and 1,845 BOE per day (86% oil), respectively, during 24-hour IP tests. The SST 6 State #123H well has produced approximately 240,000 BOE (70% oil) in its first eight months of production, and the SST 6 State #124H well has produced approximately 180,000 BOE (73% oil) in its first eight months of production. +In addition, we believe recent Wolfcamp wells drilled by Matador and other operators demonstrate the prospectivity of the Wolfcamp formation moving north in the Delaware Basin. We achieved positive Wolfcamp results in the Ranger asset area with the recent completion of the Verna Rae Federal Com #204H (Verna Rae #204H) well about three miles southwest of our Mallon wells. The Verna Rae #204H well flowed 1,586 BOE per day (90% oil) during a 24-hour IP test. +Antelope Ridge Asset Area - Lea County, New Mexico +We operated one to two drilling rigs in our Antelope Ridge asset area during 2018. We completed and turned to sales 29 gross (13.2 net) horizontal wells in this asset area in 2018, including 14 gross (12.3 net) operated and 15 gross (0.9 net) non-operated wells. As we began to delineate the Antelope Ridge asset area during 2018, we tested six different intervals, completing wells in the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower. +In particular, we were pleased with our delineation of the Wolfcamp A-Lower in the Antelope Ridge asset area. The Strong 14-24S-33E AR #214H (Strong #214H) well, our second Wolfcamp A-Lower test in the Antelope Ridge asset area, flowed 3,670 BOE per day (77% oil) during a 24-hour IP test. The Strong #214H well was a successful follow-up to our initial Wolfcamp A-Lower well in the Antelope Ridge asset area, the Leo Thorsness 13-24S-33E AR #211H (Leo Thorsness #211H) well, which flowed 2,906 BOE per day (72% oil) during a 24-hour IP test. The Strong #214H well has produced approximately 225,000 BOE (75% oil) in its first four months of production, and the Leo Thorsness #211H well has produced approximately 325,000 BOE (72% oil) in its first 11 months of production. +We also achieved several strong results in the Bone Spring in the Antelope Ridge asset area. The Irvin Wall State Com #131H (Irvin Wall #131H) well, our initial Third Bone Spring test in the Antelope Ridge asset area, flowed 2,343 BOE per day (81% oil) during a 24-hour IP test. The Irvin Wall #131H well has produced approximately 150,000 BOE (85% oil) in its first seven months of production. In addition, the Bill Alexander State Com #111H (Bill Alexander #111H) well, our second First Bone Spring test in the Antelope Ridge asset area, flowed 1,808 BOE per day (79% oil) during a 24-hour IP test. The Bill Alexander #111H well was a strong follow-up test of the First Bone Spring formation north of our initial First Bone Spring completion in the Antelope Ridge asset area, the Marlan Downey 9-23S-35E AR #111H well, which tested 1,491 BOE per day (82% oil) during a 24-hour IP test. The Bill Alexander #111H well has produced approximately 175,000 BOE (80% oil) in its first seven months of production. +9 +Table of Contents +Twin Lakes Asset Area - Lea County, New Mexico +In 2018, we performed our first test of the Wolfcamp D formation in the western portion of our Twin Lakes asset area in northern Lea County, New Mexico. This well, the Northeast Kemnitz #233H well, tested approximately 675 BOE per day (84% oil) on electric submersible pump during a 24-hour IP test. This well has exhibited a shallow production decline similar to th e D. Culbertson 26-15S-36E TL State #234H (D. Culbertson #234H) well, which was drilled and completed in 2017 and tested approximately 600 BOE per day (82% oil) during a 24-hour IP test. At December 31, 2018, we estimated an ultimate recovery of approximately 400,000 BOE from the D. Culbertson #234H well. Oil production from the D. Culbertson #234H well has been essentially flat, averaging approximately 110 Bbl of oil per day over the past 18 months, resulting in upward revisions to its estimated ultimate recovery. +Stateline Asset Area - Eddy County, New Mexico +In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net undeveloped leasehold acres prospective for multiple geologic targets. The acquired leases are federal leases and provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. As a result, we will retain an additional 17% of the net production from each well drilled and completed on these properties. The large majority of the acquired acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. The BLM has formally issued these leases, and we have begun actively pursuing drilling permits on these tracts. We expect to begin drilling operations on these properties in early 2020. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2018 , our properties included approximately 32,000 gross ( 28,900 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 93% of our Eagle Ford acreage was held by production at December 31, 2018 , and essentially all of our Eagle Ford acreage was either held by production at December 31, 2018 or not burdened by lease expirations before 2020 . +In early October 2018, we added one operated drilling rig to conduct a short-term drilling program in South Texas to drill up to 10 wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and to hold by production almost all of our remaining undeveloped Eagle Ford acreage. This rig operated in South Texas throughout the fourth quarter of 2018 and into early 2019. When drilling operations were finalized on the ninth well in early February 2019, this rig was released and was not moved to the Delaware Basin as we had previously anticipated. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight wells, including one well drilled in the Austin Chalk, are expected to be completed and turned to sales late in the first quarter or early in the second quarter of 2019. +Our average daily oil equivalent production from the Eagle Ford shale decreased 28% to 3,158 BOE per day, including 2,485 Bbl of oil per day and 4.0 MMcf of natural gas per day, during 2018 , as compared to 4,413 BOE per day, including 3,475 Bbl of oil per day and 5.6 MMcf of natural gas per day, during 2017 . For the year ended December 31, 2018 , 6% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 11% for the year ended December 31, 2017 . +At December 31, 2018 , approximately 6% of our estimated total proved oil and natural gas reserves, or 12.2 million BOE, was attributable to the Eagle Ford shale, including approximately 8.5 million Bbl of oil and 21.9 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 7% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2018 , as compared to approximately 11% of our proved oil reserves and 5% of our proved natural gas reserves at December 31, 2017 . +At December 31, 2018 , we had identified 238 gross ( 206.9 net) engineered locations for potential future drilling on our Eagle Ford acreage. Each drilling location assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into +10 +Table of Contents +account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2018 , these 238 gross ( 206.9 net) identified drilling locations included 17 gross (17.0 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2018 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though recent activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals. +Northwest Louisiana and East Texas — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2018 , although we did participate in the drilling and completion of eight gross (0.2 net) non-operated Haynesville shale wells that were turned to sales in 2018 . We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2019 . +At December 31, 2018 , we held approximately 25,500 gross ( 22,800 net) acres in Northwest Louisiana and East Texas, including 19,600 gross ( 12,000 net) acres in the Haynesville shale play and 21,100 gross ( 18,600 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 32% of the 13,200 gross ( 6,400 net) acres that we consider to be in the core area of the Haynesville shale play. +For the year ended December 31, 2018 , approximately 7% of our average daily oil equivalent production, or 3,733 BOE per day, including 12 Bbl of oil per day and 22.3 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 17% of our daily natural gas production during 2018 , as compared to approximately 29% of our daily natural gas production during 2017 . During the year ended December 31, 2017 , approximately 13% of our average daily oil equivalent production, or 5,060 BOE per day, including 12 Bbl of oil per day and 30.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2018 , approximately 16% of our daily natural gas production, or 20.5 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1% , or 1.8 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2017 , approximately 27% of our daily natural gas production, or 28.3 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 2% , or 2.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2018 , approximately 5% of our estimated total proved reserves, or 10.9 million BOE, was attributable to the Haynesville shale with another 0.3% of our proved reserves, or 0.7 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2018 , we had identified 395 gross ( 100.2 net) engineered locations for potential future drilling in the Haynesville shale play and 71 gross ( 49.2 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into account criteria such as +11 +Table of Contents +anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 395 gross ( 100.2 net) locations identified for future drilling on our Haynesville acreage, 321 gross (47.2 net) locations have been identified within the 13,200 gross ( 6,400 net) acres that we believe are located in the core area of the Haynesville shale play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2018 , these potential future drilling locations included 14 gross (4.9 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of Five Point. The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo. We earned $14.7 million in performance incentives effective January 31, 2018, which was paid by Five Point in the first quarter of 2018. Through January 31, 2019, we had earned an additional $14.7 million in performance incentives that we expect to be paid by Five Point in the first quarter of 2019 and may earn up to an additional $44.1 million in performance incentives over the next three years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo continues to provide firm capacity service to us at market rates, while also being a midstream service provider to other customers in and around our Wolf and Rustler Breaks asset areas. +In February 2019, we announced an expansion of our midstream business with the formation of San Mateo II. For additional information regarding this strategic joint venture, see “—2019 Recent Developments.” +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During 2017, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 60 MMcf of natural gas per day. As noted above in “—2018 Highlights—Midstream Highlights,” San Mateo completed this expansion of the Black River Processing Plant in late March 2018, bringing the total designed inlet capacity of the Black River Processing Plant to 260 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and production development activities in the Delaware Basin and offers processing opportunities for other producers’ development efforts. +As noted above in “—2018 Highlights—Midstream Highlights,” in October 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including us, at December 31, 2018 , San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant. +In addition, in early 2018, San Mateo completed an NGL pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and +12 +Table of Contents +fractionation costs and (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connected our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo in February 2017. +At December 31, 2018 , San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2018 , San Mateo gathered approximately 46.1 Bcf of natural gas, as compared to 32.1 Bcf of natural gas gathered during the year ended December 31, 2017 . In addition, during the year ended December 31, 2018 , San Mateo processed approximately 32.3 Bcf of natural gas, as compared to 18.4 Bcf of natural gas processed during the year ended December 31, 2017 . +Crude Oil Gathering and Transportation Assets +As noted above in “—2018 Highlights—Midstream Highlights,” subsidiaries of San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +Also, as noted above in “—2018 Highlights—Midstream Highlights,” San Mateo completed its expanded Wolf Oil Pipeline System in May 2018 and placed into service the Rustler Breaks Oil Pipeline System in December 2018. With the Wolf Oil Pipeline System and the Rustler Breaks Oil Pipeline System (collectively, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2018 , we estimated we had on pipe almost all of our oil production from the Wolf and Rustler Breaks asset areas, which comprised approximately 70% of our Delaware Basin oil production in the fourth quarter of 2018. With the San Mateo Oil Pipeline Systems in service, we expect to improve our oil price realizations in the Wolf and Rustler Breaks asset areas through the elimination of higher priced trucking services. +At December 31, 2018 , the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from origin points in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains Pipeline, L.P. and two trucking facilities. During the year ended December 31, 2018 , the San Mateo Oil Pipeline Systems had throughput of approximately 2.0 million Bbl of oil, as compared to 0.5 million Bbl of oil throughput during the year ended December 31, 2017 . +Produced Water Gathering and Disposal Assets +During 2018, San Mateo placed into service three commercial salt water disposal wells in the Rustler Breaks asset area and placed into service one additional commercial salt water disposal well there in February 2019, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to six at February 26, 2019 . In addition to its six commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, at February 26, 2019 , San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, and San Mateo’s salt water gathering systems included salt water gathering pipelines in the Rustler Breaks and Wolf asset areas. At February 26, 2019 , San Mateo had a designed disposal capacity of approximately 250,000 Bbl of salt water per day. +As noted above in “—2018 Highlights—Midstream Highlights,” in June 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. +During the year ended December 31, 2018 , San Mateo gathered approximately 44.0 million Bbl of salt water, as compared to 20.0 million Bbl of salt water gathered during the year ended December 31, 2017 . In addition, during the year ended December 31, 2018 , San Mateo disposed of approximately 47.5 million Bbl of salt water, as compared to 23.6 million Bbl of salt water disposed of during the year ended December 31, 2017 . +South Texas / Northwest Louisiana and East Texas +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and treat natural gas from most of our operated leases and from third parties and five non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana and East Texas are not part of San Mateo. +13 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2018, 2017 and 2016 . +Year Ended December 31, +2018 +2017 +2016 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +11,141 +7,851 +5,096 +Natural gas (Bcf) +47.3 +38.2 +30.5 +Total oil equivalent (MBOE) (1) +19,026 +14,212 +10,180 +Average daily production (BOE/d) (1) +52,128 +38,936 +27,813 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +57.04 +$ +49.28 +$ +41.19 +Oil, with realized derivatives (per Bbl) +$ +57.38 +$ +48.81 +$ +42.34 +Natural gas, without realized derivatives (per Mcf) +$ +3.49 +$ +3.72 +$ +2.66 +Natural gas, with realized derivatives (per Mcf) +$ +3.46 +$ +3.70 +$ +2.78 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +4.00 +$ +4.10 +$ +4.23 +Lease operating +$ +4.89 +$ +4.74 +$ +5.52 +Plant and other midstream services operating +$ +1.29 +$ +0.92 +$ +0.53 +Depletion, depreciation and amortization +$ +13.94 +$ +12.49 +$ +11.99 +General and administrative +$ +3.64 +$ +4.65 +$ +5.41 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +10,230 +907 +— +4 +11,141 +Natural gas (Bcf) +37.7 +1.5 +7.5 +0.6 +47.3 +Total oil equivalent (MBOE) (3) +16,512 +1,152 +1,247 +115 +19,026 +Percentage of total annual net production +86.8 +% +6.0 +% +6.6 +% +0.6 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +28,026 +2,485 +— +12 +30,523 +Natural gas (MMcf/d) +103.3 +4.0 +20.5 +1.8 +129.6 +Total oil equivalent (BOE/d) +45,237 +3,158 +3,417 +316 +52,128 +Average Sales Prices (4) +Oil (per Bbl) +$ +56.12 +$ +67.40 +$ +— +$ +64.72 +$ +57.04 +Natural gas (per Mcf) +$ +3.55 +$ +5.46 +$ +2.85 +$ +2.80 +$ +3.49 +Total oil equivalent (per BOE) +$ +42.88 +$ +60.02 +$ +17.09 +$ +18.59 +$ +42.08 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +4.79 +$ +17.25 +$ +5.41 +$ +19.11 +$ +5.68 +__________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +14 +Table of Contents +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +6,579 +1,268 +— +4 +7,851 +Natural gas (Bcf) +25.1 +2.0 +10.3 +0.8 +38.2 +Total oil equivalent (MBOE) (3) +10,754 +1,611 +1,714 +133 +14,212 +Percentage of total annual net production +75.7 +% +11.3 +% +12.1 +% +0.9 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +18,023 +3,475 +— +12 +21,510 +Natural gas (MMcf/d) +68.6 +5.6 +28.3 +2.1 +104.6 +Total oil equivalent (BOE/d) +29,463 +4,413 +4,697 +363 +38,936 +Average Sales Prices (4) +Oil (per Bbl) +$ +49.08 +$ +50.29 +$ +— +$ +45.52 +$ +49.28 +Natural gas (per Mcf) +$ +4.03 +$ +4.69 +$ +2.83 +$ +2.79 +$ +3.72 +Total oil equivalent (per BOE) +$ +39.41 +$ +45.58 +$ +16.96 +$ +17.69 +$ +37.20 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.80 +$ +10.92 +$ +4.21 +$ +16.77 +$ +6.29 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana/East Texas +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +3,805 +1,286 +— +5 +5,096 +Natural gas (Bcf) +12.2 +3.1 +14.3 +0.9 +30.5 +Total oil equivalent (MBOE) (3) +5,834 +1,813 +2,385 +148 +10,180 +Percentage of total annual net production +57.3 +% +17.8 +% +23.4 +% +1.5 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +10,395 +3,517 +— +12 +13,924 +Natural gas (MMcf/d) +33.3 +8.6 +39.1 +2.3 +83.3 +Total oil equivalent (BOE/d) +15,941 +4,952 +6,517 +403 +27,813 +Average Sales Prices (4) +Oil (per Bbl) +$ +41.76 +$ +39.49 +$ +— +$ +38.78 +$ +41.19 +Natural gas (per Mcf) +$ +3.15 +$ +3.11 +$ +2.17 +$ +2.27 +$ +2.66 +Total oil equivalent (per BOE) +$ +33.81 +$ +33.46 +$ +13.04 +$ +14.39 +$ +28.60 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +7.32 +$ +12.74 +$ +4.73 +$ +17.07 +$ +7.82 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 increased 34% from our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have significantly reduced our operated activity since late 2014 and early 2015. Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, as compared to 38,936 BOE per day for the year ended December 31, 2017 . Our average daily oil production for the year ended December 31, 2018 was 30,524 Bbl of oil per day, an increase of 42% from 21,510 Bbl of oil per day for the year ended December 31, 2017 . Our average daily natural gas production for the year ended December 31, 2018 was 129.6 MMcf of natural gas per day, an increase of 24% from 104.6 MMcf of natural gas per day for the year ended December 31, 2017 . +Our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 increased 40% from our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2017 was 38,936 BOE per day, as compared to 27,813 BOE per day for the year ended December 31, 2016 . Our average daily oil production for the year ended December 31, 2017 was 21,510 Bbl of oil per day, an increase of 54% from 13,924 Bbl of oil per day for the year ended December 31, 2016 . Our average daily natural gas production for the year ended December 31, 2017 was 104.6 MMcf of natural gas per day, an increase of 25% from 83.3 MMcf of natural gas per day for the year ended December 31, 2016 . +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2018 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 77% in all wells that we operated at December 31, 2018 . For wells where we are not the operator, our working interests range from less than 1% to as much as just over 50%, and average approximately 11%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +519 +241.0 +111 +49.7 +630 +290.7 +South Texas: +Eagle Ford (2) +144 +118.5 +4 +4.0 +148 +122.5 +Northwest Louisiana/East Texas: +Haynesville +— +— +227 +20.4 +227 +20.4 +Cotton Valley (3) +2 +2.0 +77 +51.3 +79 +53.3 +Area Total +2 +2.0 +304 +71.7 +306 +73.7 +Total +665 +361.5 +419 +125.4 +1,084 +486.9 +__________________ +(1) +Includes 224 gross (58.6 net) vertical wells that were acquired in multiple transactions. +(2) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2018, 2017 and 2016 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +17 +Table of Contents +At December 31, (1) +2018 +2017 +2016 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +123,401 +86,743 +56,977 +Natural Gas (Bcf) +551.5 +396.2 +292.6 +Total (MBOE) (3) +215,313 +152,771 +105,752 +Estimated proved developed reserves: +Oil (MBbl) +53,223 +36,966 +22,604 +Natural Gas (Bcf) +246.2 +190.1 +126.8 +Total (MBOE) (3) +94,261 +68,651 +43,731 +Percent developed +43.8 +% +44.9 +% +41.4 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +70,178 +49,777 +34,373 +Natural Gas (Bcf) +305.2 +206.1 +165.9 +Total (MBOE) (3) +121,052 +84,120 +62,021 +Standardized Measure (4) (in millions) +$ +2,250.6 +$ +1,258.6 +$ +575.0 +PV-10 (5) (in millions) +$ +2,579.3 +$ +1,333.4 +$ +581.5 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas, for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas, and for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2018, 2017 and 2016 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2018, 2017 and 2016 were, in millions, $328.7 , $74.8 and $6.5 , respectively. +Our estimated total proved oil and natural gas reserves increase d 41% from 152.8 million BOE at December 31, 2017 to 215.3 million BOE at December 31, 2018 . We added 69.6 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2018, approximately 3.7 times our 2018 annual production of 19.0 million BOE. Our proved oil reserves grew 42% from approximately 86.7 million Bbl at December 31, 2017 to approximately 123.4 million Bbl at December 31, 2018 . Our proved natural gas reserves increase d 39% from 396.2 Bcf at December 31, 2017 to 551.5 Bcf at December 31, 2018 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2018. We realized approximately 11.3 million BOE in net upward revisions to our proved reserves during 2018 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2017. Our proved reserves to production ratio at December 31, 2018 was 11.3 , an increase of 4% from 10.8 at December 31, 2017. +Over the past two years, our estimated total proved oil and natural gas reserves more than doubled, increasing 104% from 105.8 million BOE at December 31, 2016 to 215.3 million Bbl at December 31, 2018 . Our proved oil reserves grew 117% from 57.0 million Bbl at December 31, 2016 to 123.4 million Bbl at December 31, 2018 . Our proved developed oil reserves increased 135% from 22.6 million Bbl at December 31, 2016 to 53.2 million Bbl at December 31, 2018 . +18 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increase d 79% from $1.26 billion at December 31, 2017 to $2.25 billion at December 31, 2018 . The PV-10 of our total proved oil and natural gas reserves increase d 93% from $1.33 billion at December 31, 2017 to $2.58 billion at December 31, 2018 . The increases in our Standardized Measure and PV-10 are primarily a result of our delineation and development drilling activities in the Delaware Basin during 2018 and higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2018 , as compared to December 31, 2017 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2018 were $62.04 per Bbl and $3.10 per MMBtu, an increase of 30% and 4% , respectively, as compared to average oil and natural gas prices of $47.79 per Bbl and $2.98 per MMBtu used to estimate proved reserves at December 31, 2017 . Our total proved reserves were made up of 57% oil and 43% natural gas at December 31, 2018 , as compared to 57% oil and 43% natural gas at December 31, 2017 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +Our proved developed oil and natural gas reserves increase d 37% from 68.7 million BOE at December 31, 2017 to 94.3 million BOE at December 31, 2018 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 44% from 37.0 million Bbl at December 31, 2017 to 53.2 million Bbl at December 31, 2018 . Our proved developed natural gas reserves increase d 30% from 190.1 Bcf at December 31, 2017 to 246.2 Bcf at December 31, 2018 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2018 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2017 +68,651 +Extensions and discoveries +14,666 +Purchases of minerals-in-place +596 +Revisions of prior estimates +3,091 +Production +(19,026 +) +Conversion of proved undeveloped to proved developed +26,283 +As of December 31, 2018 +94,261 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d 44% from 84.1 million BOE at December 31, 2017 to 121.1 million BOE at December 31, 2018 . Our proved undeveloped oil and natural gas reserves increased from 49.8 million Bbl and 206.1 Bcf, respectively, at December 31, 2017 to 70.2 million Bbl and 305.2 Bcf, respectively, at December 31, 2018 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2018 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2018 within five years of booking these reserves. +19 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2018 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2017 +84,120 +Extensions and discoveries +54,980 +Purchases of minerals-in-place +— +Revisions of prior estimates +8,235 +Conversion of proved undeveloped to proved developed +(26,283 +) +As of December 31, 2018 +121,052 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2015, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2015 +2,854 +23.4 +6,747 +104,989 +2016 +4,705 +13.1 +6,883 +94,579 +2017 +9,300 +45.0 +16,808 +211,860 +2018 +16,009 +61.7 +26,283 +$ +356,830 +Total +32,868 +143.2 +56,721 +$ +768,258 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2018 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +114,823 +460.0 +191,490 +$ +2,056.7 +$ +2,357.1 +South Texas: +Eagle Ford (5) +8,537 +21.9 +12,189 +160.9 +184.4 +Northwest Louisiana/East Texas: +Haynesville +— +65.5 +10,919 +31.0 +35.5 +Cotton Valley (6) +41 +4.1 +715 +2.0 +2.3 +Area Total +41 +69.6 +11,634 +33.0 +37.8 +Total +123,401 +551.5 +215,313 +$ +2,250.6 +$ +2,579.3 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2018 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2018 were approximately $ 328.7 million . +20 +Table of Contents +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Executive Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 41 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2018 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +123,000 +71,900 +99,200 +60,100 +222,200 +132,000 +South Texas: +Eagle Ford +29,900 +26,800 +2,100 +2,100 +32,000 +28,900 +Northwest Louisiana/East Texas (1) : +Haynesville +19,000 +11,500 +600 +500 +19,600 +12,000 +Cotton Valley +20,400 +18,500 +700 +100 +21,100 +18,600 +Area Total (2) +24,300 +22,200 +1,200 +600 +25,500 +22,800 +Total +177,200 +120,900 +102,500 +62,800 +279,700 +183,700 +__________________ +(1) +Developed acres include 2,800 gross and net mineral acres in Northwest Louisiana. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +21 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2018 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2024 and beyond totals 13,500 net acres, of which 8,800 net acres do not expire until 2028. +Acres +Acres +Acres +Acres +Acres +Expiring 2019 +Expiring 2020 +Expiring 2021 +Expiring 2022 +Expiring 2023 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +13,900 +9,400 +16,400 +8,900 +25,100 +14,900 +7,600 +8,200 +4,000 +5,400 +South Texas: +Eagle Ford +100 +100 +1,600 +1,500 +400 +400 +— +— +— +— +Northwest Louisiana/East Texas: +Haynesville +300 +300 +200 +200 +— +— +— +— +— +— +Cotton Valley +— +— +— +— +— +— +— +— +— +— +Area Total (2) +300 +300 +200 +200 +— +— +— +— +— +— +Total +14,300 +9,800 +18,200 +10,600 +25,500 +15,300 +7,600 +8,200 +4,000 +5,400 +__________________ +(1) +Approximately 49% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage through our 2019 drilling activities or by paying an additional lease bonus, where applicable. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2018 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2018, 2017 and 2016 . +Year Ended December 31, +2018 +2017 +2016 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +118 +54.7 +72 +43.7 +44 +23.5 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +35 +20.8 +33 +22.3 +28 +15.6 +Dry +— +— +— +— +— +— +Total Wells +Productive +153 +75.5 +105 +66.0 +72 +39.1 +Dry +— +— +— +— +— +— +22 +Table of Contents +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries (“OPEC”), weather conditions, hurricanes in the Gulf Coast region, oil and natural gas storage levels, transportation capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +For the years ended December 31, 2018, 2017 and 2016 , we had four, four and three significant purchasers, respectively, that accounted for approximately 60% , 60% and 48% , respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. We intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +23 +Table of Contents +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and +24 +Table of Contents +limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believed, as of February 26, 2019 , that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System, which is subject to FERC jurisdiction, includes approximately 17 miles of 10-inch diameter crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC jurisdiction by any entity, to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to significantly increase the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”), went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The +25 +Table of Contents +Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors — We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In January 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would start at $0.60 per MMBtu in 2020 and escalate to $3.00 per MMBtu by 2024. If passed, such a surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors — Recently Enacted Tax Legislation May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor +26 +Table of Contents +all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”), and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the revision expands the scope of jurisdiction of the CWA, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. However, citing uncertainty caused by litigation surrounding the validity of this rule, in 2018 the EPA and the Corps announced a two-year stay of the application of the rule. Federal district court decisions have preserved the stay in Texas, New Mexico and Louisiana, and such jurisdictions remain subject to pre-2015 WOTUS regulations. As noted, litigation surrounding this rule is ongoing. On December 11, 2018, the EPA and the Corps released a proposal to revise the 2015 Clean Water Rule so as to narrow the regulatory definition of WOTUS, with a 60-day comment period to follow. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the +27 +Table of Contents +environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce, while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission (the “TRC”), adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to +28 +Table of Contents +the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. We do not expect these developments to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In February 2019, a bill was introduced in the New Mexico Senate to place a moratorium on hydraulic fracturing that, if enacted, would last through June 1, 2023. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +Oil and natural gas exploration and production, operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act (the “ESA”), was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +29 +Table of Contents +A significant portion of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 13 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2018 , we had 264 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +30 +Table of Contents +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. \ No newline at end of file diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/item13.txt b/raw/filings/0001520006/2018/0001520006-19-000048/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2018/0001520006-19-000048/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/item9a.txt b/raw/filings/0001520006/2018/0001520006-19-000048/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..5c384d3770e4086708a8bea4a7ac0705f94b643b --- /dev/null +++ b/raw/filings/0001520006/2018/0001520006-19-000048/item9a.txt @@ -0,0 +1,31 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2018 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2018 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2018 as included herein. +85 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +86 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2018 and 2017 , the related statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018 , and the related notes (collectively, the “consolidated financial statements”), and our report dated March 1, 2019 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +March 1, 2019 +87 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/rp_note.txt b/raw/filings/0001520006/2018/0001520006-19-000048/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2018/0001520006-19-000048/rpt_disclosure.txt b/raw/filings/0001520006/2018/0001520006-19-000048/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ab374c6eeea97e0c9434c4a06dca25ac7101f32d --- /dev/null +++ b/raw/filings/0001520006/2018/0001520006-19-000048/rpt_disclosure.txt @@ -0,0 +1,108 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2018 there was not, nor was there proposed as of December 31, 2018, any transaction or series of similar transactions to which we +were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the immediate family of any of the +foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation—Compensation Discussion and +Analysis” above. +HEYCO Joint Ventures +In June 2015, the Company entered into two joint ventures (the +“Joint Ventures”) to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of Harvey E. Yates Company. The Company acquired Harvey E. Yates +Company in a 2015 merger (the “HEYCO Merger.”) The HEYCO Affiliates are owned by George M. Yates, who was appointed to the Board on April 28, 2015 in accordance with the terms of the HEYCO Merger, and certain of his affiliates. +Mr. Yates’ term as a director expired at the 2018 Annual Meeting. Pursuant to the terms of the Joint Ventures, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held +by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of +December 31, 2018, the Company had contributed an aggregate of approximately $9.4 million to the two entities. The Company’s contributions are being used to fund capital expenditures associated with the interests owned by the Joint +Ventures as well as to fund acquisitions by the Joint Ventures of other non-operated acreage opportunities. +The Audit +Committee reviewed the terms of the Joint Ventures for potential conflicts of interest under the Company’s related party transaction policy, effective October 12, 2011 (the “Related Party Transaction Policy”), and, after being +fully informed as to Mr. Yates’ relationship and interest and all other material facts related to the Joint Ventures, determined that the Joint Ventures were fair to the Company and recommended the Joint Ventures to the full Board for +approval and ratification. The Board subsequently approved and ratified the Joint Ventures. +In addition, in light of Mr. Yates’ ongoing services to HEYCO +Energy Group, Inc., the Board, in accordance with Texas corporate law, adopted resolutions that renounced and provided for a waiver of certain corporate opportunities with respect to Mr. Yates. As a result, during his term on the Board, +Mr. Yates had no fiduciary duty to present certain corporate opportunities related to Mr. Yates’ existing oil and natural gas holdings and/or in areas where Matador did not then operate. +Working Interest and Overriding Royalty Interest Owners +Certain related parties, including Mr. Foran, certain of +Mr. Foran’s affiliated entities (collectively, the “Foran Entities”) and certain HEYCO Affiliates or entities controlled by members of Mr. Yates’ family (the “Yates Entities” and, collectively with the Foran +Entities, the “Interest Owners”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, the +Interest Owners are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Interest Owners are entitled to +receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2018, revenues, net of costs, received by the Yates Entities in their capacities as working interest owners or +overriding royalty interest owners were approximately $10.6 million (the “Yates Net Revenue Payments”). During 2018, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners or overriding +royalty interest owners were approximately $1.7 million (collectively with the Yates Net Revenue Payments, the “Related Net Revenue Payments”). The Related Net Revenue Payments represent approximately 4.5% of our total third-party net +revenue payments during 2018. +2019 +Proxy Statement | Matador Resources Company 79 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +In our capacity as operator, we incur drilling and operating +costs that are billed to our partners based on their respective working interests. During 2018, our joint interest billings to the Yates Entities attributable to their share of costs were approximately $10.8 million (the “Yates +Billings”) and our joint interest billings to the Foran Entities attributable to their share of costs were approximately $0.4 million (collectively with the Yates Billings, the “Related Joint Interest Billings”). The Related +Joint Interest Billings represent approximately 1.3% of our total joint interest billings during 2018. As a result of this ownership by the Interest Owners, from time to time, we will be in a net receivable or net payable position with certain of +the Interest Owners. We do not consider any net receivables from these parties to be uncollectible. +The Audit Committee reviewed the terms of the working interests +and/or overriding royalty interests of the Interest Owners for potential conflicts of interest under the Related Party Transaction Policy, and, after being fully informed as to Mr. Yates’ and Mr. Foran’s respective relationships +and interests in such transactions and all other material facts related to the Related Net Revenue Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest +Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the +transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Certain Employment Relationships +Billy E. Goodwin, Executive Vice President and Head of +Operations, was appointed as an executive officer of the Company in connection with his February 2016 promotion to Senior Vice President—Operations. Two of Mr. Goodwin’s adult children have been employees of the Company since 2014 and +2015, respectively, and each earned in 2018, and are expected to be compensated in 2019, between $120,000 and $700,000. One of Mr. Goodwin’s children has a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa +and over nine years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other child has a Bachelor of Science in Business Administration degree +in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He also has over nine years of industry experience, including as a drilling fluids engineer for a +publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangements for potential conflicts of interest under the Company’s +Related Party Transaction Policy and, after being fully informed as to the employment arrangements and historical and anticipated compensation of Mr. Goodwin’s adult children, and all other material facts related to the relationship, +determined that the employment arrangements were fair to the Company and recommended the employment arrangements to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s sister-in-law +has been an employee of the Company since 2016 and earned in 2018, and is expected to be compensated in 2019, between $120,000 and $250,000. Mr. Baribault’s +sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist University Legal Assistants +Program. She has over 37 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being +fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts +related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment +arrangement. +An adult child of Mr. Foran has been an employee of the Company since 2015 and earned in 2018, and is expected to be compensated in 2019, between +$120,000 and $200,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than eight years of +industry experience, including with another publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment +80 Matador Resources Company | 2019 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +arrangement for potential conflicts of interest under the Company’s Related Party Transaction Policy and, after being fully informed as to the employment arrangement and historical and +anticipated compensation of Mr. Foran’s adult child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board +for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +Procedures for Approval of Related +Party Transactions +Pursuant to the Related Party +Transaction Policy, a “Related Party Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, +or any material amendment to any such transaction, involving a Related Party (as defined below) and in which we are a participant, other than: +• +a transaction involving compensation of directors; +• +a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, +change in control provision or agreement or a special supplemental benefit for an executive officer; +• +a transaction available to all employees generally or to all salaried employees generally; +• +a transaction with a Related Party involving less than $120,000; +• +a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity +securities and all holders of that class receive the same benefit on a pro rata basis; or +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that +involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. +“Related Party” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors +or nominees for directors; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, +sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• +any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the +foregoing persons is a general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Party Transaction Policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or +disapproval of the Related Party Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all +material facts of the Related Party Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be +disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +2019 +Proxy Statement | Matador Resources Company 81 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/filing.txt b/raw/filings/0001520006/2019/0001520006-20-000037/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..beb3de5372b5dd0c53d427690a59a54ce07443d8 --- /dev/null +++ b/raw/filings/0001520006/2019/0001520006-20-000037/filing.txt @@ -0,0 +1,9780 @@ +Document +false --12-31 FY 2019 0001520006 8400 P1M P5Y P15Y P5Y P6Y P15Y P7Y P30Y 0 0.01 0.01 160000000 160000000 108513597 116374503 108510160 116353590 0.05 0 0 16200000 288000000 255000000 P5Y P3Y P3Y P1Y 23.4 19.71 13.22 29.68 22.70 15.00 3437 20913 +0001520006 +2019-01-01 +2019-12-31 +0001520006 +2020-02-28 +0001520006 +2019-06-30 +0001520006 +2019-12-31 +0001520006 +2018-12-31 +0001520006 +2017-01-01 +2017-12-31 +0001520006 +2018-01-01 +2018-12-31 +0001520006 +us-gaap:NaturalGasMidstreamMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:NaturalGasSalesMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:NaturalGasSalesMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OilAndGasMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:NaturalGasMidstreamMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OilAndGasMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OilAndGasMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:NaturalGasMidstreamMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:NaturalGasSalesMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CommonStockMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2017-12-31 +0001520006 +us-gaap:ParentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2017-12-31 +0001520006 +us-gaap:CommonStockMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:ParentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:TreasuryStockMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:CommonStockMember +2018-12-31 +0001520006 +us-gaap:TreasuryStockMember +2016-12-31 +0001520006 +2017-12-31 +0001520006 +us-gaap:TreasuryStockMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2016-12-31 +0001520006 +us-gaap:ParentMember +2018-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:CommonStockMember +2016-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2016-12-31 +0001520006 +us-gaap:CommonStockMember +2017-12-31 +0001520006 +us-gaap:ParentMember +2016-12-31 +0001520006 +us-gaap:TreasuryStockMember +2018-12-31 +0001520006 +2016-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2016-12-31 +0001520006 +us-gaap:TreasuryStockMember +2017-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2018-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2018-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2017-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2018-12-31 +0001520006 +us-gaap:ParentMember +2017-12-31 +0001520006 +us-gaap:TreasuryStockMember +2019-12-31 +0001520006 +us-gaap:CommonStockMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:ParentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:CommonStockMember +2019-12-31 +0001520006 +us-gaap:TreasuryStockMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:ParentMember +2019-12-31 +0001520006 +mtdr:SanMateoIIMember +us-gaap:NoncontrollingInterestMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2019-12-31 +0001520006 +us-gaap:RetainedEarningsMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoIIMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoIIMember +us-gaap:AdditionalPaidInCapitalMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoIMember +us-gaap:ParentMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoIIMember +us-gaap:ParentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:AdditionalPaidInCapitalMember +2019-12-31 +0001520006 +mtdr:SanMateoIMember +us-gaap:AdditionalPaidInCapitalMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:NoncontrollingInterestMember +2019-12-31 +0001520006 +mtdr:SanMateoIMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:PlainsMarketingL.P.Member +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2019-01-01 +2019-12-31 +0001520006 +srt:MaximumMember +us-gaap:MachineryAndEquipmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:MachineryAndEquipmentMember +2019-01-01 +2019-12-31 +0001520006 +srt:MinimumMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:AccountsReceivableMember +2017-01-01 +2017-12-31 +0001520006 +2019-01-01 +0001520006 +srt:MaximumMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:ShellTradingUSCompanyMember +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:RevenueFromContractWithCustomerMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:EmployeeStockOptionMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:WesternRefiningOilMember +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:PlainsMarketingL.P.Member +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:BPAmericaProductionCompanyMember +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:AccountsReceivableMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:EmployeeStockOptionMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:EmployeeStockOptionMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:RevenueFromContractWithCustomerMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:OccidentalEnergyMarketingInc.Member +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:BPAmericaProductionCompanyMember +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:RevenueFromContractWithCustomerMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:MachineryAndEquipmentMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:OccidentalEnergyMarketingInc.Member +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:AccountsReceivableMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:WesternRefiningOilMember +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:PlainsMarketingL.P.Member +us-gaap:RevenueFromContractWithCustomerMember +us-gaap:CustomerConcentrationRiskMember +2017-01-01 +2017-12-31 +0001520006 +srt:OilReservesMember +2019-01-01 +2019-12-31 +0001520006 +srt:NaturalGasReservesMember +2018-01-01 +2018-12-31 +0001520006 +srt:OilReservesMember +2018-01-01 +2018-12-31 +0001520006 +srt:NaturalGasReservesMember +2019-01-01 +2019-12-31 +0001520006 +srt:MinimumMember +us-gaap:MachineryAndEquipmentMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:CurrentYearMember +2019-12-31 +0001520006 +mtdr:PriorYearMember +2018-12-31 +0001520006 +mtdr:ThreeYearsandPriorMember +2016-12-31 +0001520006 +mtdr:ProjectsInceptiontoDateMember +2019-12-31 +0001520006 +mtdr:TwoYearsPriorMember +2017-12-31 +0001520006 +mtdr:BLMAcquisitionMember +2018-09-12 +2018-09-12 +0001520006 +mtdr:BLMAcquisitionMember +2018-09-12 +0001520006 +us-gaap:ComputerSoftwareIntangibleAssetMember +2019-12-31 +0001520006 +us-gaap:ComputerSoftwareIntangibleAssetMember +2018-12-31 +0001520006 +us-gaap:FurnitureAndFixturesMember +2019-12-31 +0001520006 +us-gaap:SupportEquipmentAndFacilitiesMember +2019-12-31 +0001520006 +us-gaap:FurnitureAndFixturesMember +2018-12-31 +0001520006 +us-gaap:SupportEquipmentAndFacilitiesMember +2018-12-31 +0001520006 +us-gaap:LeaseholdsAndLeaseholdImprovementsMember +2019-12-31 +0001520006 +us-gaap:LeaseholdsAndLeaseholdImprovementsMember +2018-12-31 +0001520006 +mtdr:DrillingRigLeasesMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandAndThreeStockAndIncentivePlanMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:OperatingLeaseExpenseMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OilAndGasServiceMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:GeneralAndAdministrativeExpenseMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoMidstreamMember +mtdr:RustlerBreaksAssetAreaMember +us-gaap:CorporateJointVentureMember +2017-02-17 +2017-02-17 +0001520006 +mtdr:FivePointMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2017-02-17 +2017-02-17 +0001520006 +mtdr:SanMateoMidstreamMember +mtdr:WolfAssetAreaMember +us-gaap:CorporateJointVentureMember +2017-02-17 +0001520006 +mtdr:FivePointMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2017-02-17 +0001520006 +mtdr:FivePointMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:FivePointMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-02-25 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-02-25 +2019-02-25 +0001520006 +mtdr:SanMateoMidstreamMember +mtdr:RustlerBreaksandWolfAssetAreaMember +us-gaap:CorporateJointVentureMember +2017-02-17 +2017-02-17 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2017-02-17 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2017-02-17 +2017-02-17 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-02-25 +0001520006 +mtdr:MatadorResourcesCompanyMember +mtdr:SanMateoMidstreamMember +mtdr:PropertyContributionMember +us-gaap:CorporateJointVentureMember +2019-01-01 +2019-03-31 +0001520006 +mtdr:SanMateoMidstreamMember +mtdr:RustlerBreaksAssetAreaMember +us-gaap:CorporateJointVentureMember +2017-02-17 +0001520006 +mtdr:MatadorResourcesCompanyMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-02-25 +0001520006 +mtdr:FivePointMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-12-31 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2017-02-17 +2018-01-31 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2018-02-16 +2018-02-16 +0001520006 +mtdr:MatadorResourcesCompanyMember +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2018-02-18 +2019-01-31 +0001520006 +mtdr:Additional2026NotesMember +us-gaap:DebtInstrumentRedemptionPeriodOneMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +us-gaap:RevolvingCreditFacilityMember +mtdr:ThirdAmendedCreditAgreementMember +us-gaap:SubsequentEventMember +2020-02-27 +0001520006 +mtdr:ThirdAmendedCreditAgreementMember +mtdr:FederalFundsEffectiveRateMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +2019-12-31 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +2019-10-31 +0001520006 +us-gaap:SubsequentEventMember +2020-02-25 +0001520006 +mtdr:ThirdAmendedCreditAgreementMember +2019-12-31 +0001520006 +mtdr:SeniorNotesDue2023Member +us-gaap:DebtInstrumentRedemptionPeriodOneMember +us-gaap:UnsecuredDebtMember +2018-08-21 +2018-08-21 +0001520006 +2016-12-09 +2016-12-09 +0001520006 +us-gaap:RevolvingCreditFacilityMember +2018-10-31 +0001520006 +2018-08-21 +2018-08-21 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +2018-12-19 +0001520006 +srt:MaximumMember +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +mtdr:AdjustedLIBORateMember +2018-12-19 +2018-12-19 +0001520006 +us-gaap:SeniorNotesMember +us-gaap:UnsecuredDebtMember +2019-12-31 +0001520006 +srt:MinimumMember +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +mtdr:StatutoryReserveRateMember +2018-12-19 +2018-12-19 +0001520006 +mtdr:A2026NotesOfferingMember +us-gaap:UnsecuredDebtMember +2018-08-21 +2018-08-21 +0001520006 +srt:MaximumMember +mtdr:ThirdAmendedCreditAgreementMember +mtdr:BaseRateLoanMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +mtdr:AdjustedLIBORateMember +2018-12-19 +2018-12-19 +0001520006 +mtdr:SeniorNotesDue2026Member +us-gaap:DebtInstrumentRedemptionPeriodTwoMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +mtdr:SanMateoCreditFacilityMember +mtdr:TheBankOfNovaScotiaMember +2018-12-19 +2018-12-19 +0001520006 +srt:MinimumMember +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +mtdr:AdjustedLIBORateMember +2018-12-19 +2018-12-19 +0001520006 +mtdr:ThirdAmendedCreditAgreementMember +2018-10-31 +0001520006 +mtdr:Additional2026NotesMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +mtdr:ThirdAmendedCreditAgreementMember +us-gaap:SubsequentEventMember +2020-02-27 +0001520006 +mtdr:SeniorNotesDue2026Member +us-gaap:DebtInstrumentRedemptionPeriodOneMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +mtdr:A2026NotesOfferingMember +us-gaap:UnsecuredDebtMember +2018-08-21 +0001520006 +srt:MinimumMember +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +2018-12-19 +2018-12-19 +0001520006 +us-gaap:SubsequentEventMember +2020-01-31 +0001520006 +srt:MinimumMember +mtdr:BaseRateLoanMember +2019-01-01 +2019-12-31 +0001520006 +srt:MaximumMember +mtdr:ThirdAmendedCreditAgreementMember +us-gaap:EurodollarMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:ThirdAmendedCreditAgreementMember +mtdr:LiborRateMember +2019-01-01 +2019-12-31 +0001520006 +srt:MaximumMember +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +2018-12-19 +2018-12-19 +0001520006 +mtdr:Additional2026NotesMember +us-gaap:DebtInstrumentRedemptionPeriodOneMember +us-gaap:UnsecuredDebtMember +2018-10-04 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +2019-06-30 +0001520006 +srt:MinimumMember +mtdr:ThirdAmendedCreditAgreementMember +us-gaap:EurodollarMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SeniorNotesDue2023Member +us-gaap:UnsecuredDebtMember +2018-08-21 +2018-08-21 +0001520006 +us-gaap:SubsequentEventMember +2020-02-27 +0001520006 +mtdr:SeniorNotesDue2023Member +us-gaap:UnsecuredDebtMember +2016-12-09 +0001520006 +mtdr:ThirdAmendedCreditAgreementMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:Additional2026NotesMember +us-gaap:UnsecuredDebtMember +2018-10-04 +0001520006 +mtdr:SeniorNotesDue2023Member +us-gaap:UnsecuredDebtMember +2015-04-14 +0001520006 +srt:MinimumMember +mtdr:ThirdAmendedCreditAgreementMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SeniorNotesDue2023Member +us-gaap:DebtInstrumentRedemptionPeriodOneMember +us-gaap:UnsecuredDebtMember +2016-12-09 +2016-12-09 +0001520006 +srt:MaximumMember +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +mtdr:StatutoryReserveRateMember +2018-12-19 +2018-12-19 +0001520006 +mtdr:SeniorNotesDue2023Member +us-gaap:UnsecuredDebtMember +2019-12-31 +0001520006 +srt:MaximumMember +mtdr:ThirdAmendedCreditAgreementMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +us-gaap:FederalFundsEffectiveSwapRateMember +2018-12-19 +2018-12-19 +0001520006 +mtdr:SanMateoCreditFacilityMember +2019-12-31 +0001520006 +mtdr:SeniorNotesDue2026Member +us-gaap:DebtInstrumentRedemptionPeriodThreeMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +mtdr:SeniorNotesDue2026Member +us-gaap:DebtInstrumentRedemptionPeriodFourMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +mtdr:SeniorNotesDue2026Member +us-gaap:DebtInstrumentRedemptionPeriodFiveMember +us-gaap:UnsecuredDebtMember +2018-10-04 +2018-10-04 +0001520006 +us-gaap:LineOfCreditMember +mtdr:SanMateoCreditFacilityMember +us-gaap:SubsequentEventMember +2020-02-26 +0001520006 +us-gaap:SubsequentEventMember +2020-02-26 +0001520006 +us-gaap:StateAndLocalJurisdictionMember +2019-12-31 +0001520006 +us-gaap:InternalRevenueServiceIRSMember +2019-12-31 +0001520006 +us-gaap:RestrictedStockMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember +2019-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandAndThreeStockAndIncentivePlanMember +2019-12-31 +0001520006 +us-gaap:RestrictedStockMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandAndThreeStockAndIncentivePlanMember +2018-12-31 +0001520006 +us-gaap:EmployeeStockOptionMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember +2019-12-31 +0001520006 +srt:MinimumMember +mtdr:PerformanceBasedStockUnitsMember +2019-02-01 +2019-02-28 +0001520006 +us-gaap:RestrictedStockMember +2019-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandAndThreeStockAndIncentivePlanMember +2017-12-31 +0001520006 +us-gaap:RestrictedStockMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CommonClassAMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:EmployeeStockOptionMember +2019-01-01 +2019-12-31 +0001520006 +srt:MaximumMember +us-gaap:RestrictedStockMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:EmployeeStockOptionMember +2018-01-01 +2018-12-31 +0001520006 +srt:MaximumMember +mtdr:PerformanceBasedStockUnitsMember +2019-02-01 +2019-02-28 +0001520006 +mtdr:RangeFourMember +2019-12-31 +0001520006 +mtdr:RangeThreeMember +2019-12-31 +0001520006 +mtdr:RangeThreeMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RangeTwoMember +2019-12-31 +0001520006 +mtdr:RangeOneMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RangeOneMember +2019-12-31 +0001520006 +mtdr:RangeFourMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RangeTwoMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RestrictedStockUnitsServiceBasedMember +2019-12-31 +0001520006 +mtdr:RestrictedStockUnitsPerformanceBasedMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RestrictedStockServiceBasedMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RestrictedStockServiceBasedMember +2018-12-31 +0001520006 +mtdr:RestrictedStockUnitsServiceBasedMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RestrictedStockServiceBasedMember +2019-12-31 +0001520006 +mtdr:RestrictedStockUnitsPerformanceBasedMember +2018-12-31 +0001520006 +mtdr:RestrictedStockUnitsPerformanceBasedMember +2019-12-31 +0001520006 +mtdr:RestrictedStockUnitsServiceBasedMember +2018-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:RestrictedStockLiabilityBasedMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RestrictedStockLiabilityBasedMember +2019-12-31 +0001520006 +mtdr:RestrictedStockLiabilityBasedMember +2018-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandAndThreeStockAndIncentivePlanMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:StockBasedCompensationTwoThousandAndThreeStockAndIncentivePlanMember +2017-01-01 +2017-12-31 +0001520006 +mtdr:PerformanceBasedStockUnitsMember +2019-02-01 +2019-02-26 +0001520006 +srt:MinimumMember +us-gaap:RestrictedStockMember +2019-01-01 +2019-12-31 +0001520006 +2018-05-17 +2018-05-17 +0001520006 +us-gaap:CommonStockMember +2017-06-01 +0001520006 +2016-03-11 +2016-03-11 +0001520006 +us-gaap:CommonStockMember +2017-05-31 +0001520006 +2017-10-10 +2017-10-10 +0001520006 +us-gaap:CommonStockMember +mtdr:PublicStockOfferingMember +2018-05-17 +2018-05-17 +0001520006 +us-gaap:CommonStockMember +mtdr:PublicStockOfferingMember +2017-10-10 +2017-10-10 +0001520006 +mtdr:PublicStockOfferingMember +2017-10-10 +2017-10-10 +0001520006 +mtdr:OpenCostlessCollarContractsMember +2019-12-31 +0001520006 +mtdr:OilWTIMember +mtdr:OpenCostlessCollarContractsMember +2019-12-31 +0001520006 +mtdr:OilCalculationPeriodThreeMember +mtdr:OpenSwapContractsMember +2019-12-31 +0001520006 +mtdr:OilCalculationPeriodTwoMember +mtdr:OpenSwapContractsMember +2019-12-31 +0001520006 +mtdr:OilCalculationPeriodOneMember +mtdr:OpenSwapContractsMember +2019-12-31 +0001520006 +mtdr:OpenSwapContractsMember +2019-12-31 +0001520006 +us-gaap:OtherNoncurrentLiabilitiesMember +2018-12-31 +0001520006 +us-gaap:OtherCurrentLiabilitiesMember +2018-12-31 +0001520006 +us-gaap:OtherNoncurrentLiabilitiesMember +2019-12-31 +0001520006 +us-gaap:OtherNoncurrentAssetsMember +2019-12-31 +0001520006 +us-gaap:OtherCurrentAssetsMember +2019-12-31 +0001520006 +us-gaap:OtherCurrentAssetsMember +2018-12-31 +0001520006 +us-gaap:OtherCurrentLiabilitiesMember +2019-12-31 +0001520006 +srt:NaturalGasReservesMember +mtdr:RevenuesMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RevenuesMember +2018-01-01 +2018-12-31 +0001520006 +srt:NaturalGasLiquidsReservesMember +mtdr:RevenuesMember +2018-01-01 +2018-12-31 +0001520006 +srt:OilReservesMember +mtdr:RevenuesMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RevenuesMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:RevenuesMember +2017-01-01 +2017-12-31 +0001520006 +srt:NaturalGasReservesMember +mtdr:RevenuesMember +2017-01-01 +2017-12-31 +0001520006 +srt:NaturalGasLiquidsReservesMember +mtdr:RevenuesMember +2017-01-01 +2017-12-31 +0001520006 +srt:NaturalGasReservesMember +mtdr:RevenuesMember +2018-01-01 +2018-12-31 +0001520006 +srt:OilReservesMember +mtdr:RevenuesMember +2018-01-01 +2018-12-31 +0001520006 +srt:NaturalGasLiquidsReservesMember +mtdr:RevenuesMember +2019-01-01 +2019-12-31 +0001520006 +srt:OilReservesMember +mtdr:RevenuesMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:FairValueInputsLevel3Member +us-gaap:FairValueMeasurementsRecurringMember +2019-12-31 +0001520006 +us-gaap:FairValueInputsLevel2Member +us-gaap:FairValueMeasurementsRecurringMember +2019-12-31 +0001520006 +us-gaap:FairValueMeasurementsRecurringMember +2019-12-31 +0001520006 +us-gaap:FairValueInputsLevel1Member +us-gaap:FairValueMeasurementsRecurringMember +2019-12-31 +0001520006 +us-gaap:PipelinesMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:FairValueInputsLevel3Member +us-gaap:FairValueMeasurementsRecurringMember +2018-12-31 +0001520006 +us-gaap:FairValueInputsLevel2Member +us-gaap:FairValueMeasurementsRecurringMember +2018-12-31 +0001520006 +us-gaap:FairValueInputsLevel1Member +us-gaap:FairValueMeasurementsRecurringMember +2018-12-31 +0001520006 +us-gaap:FairValueMeasurementsRecurringMember +2018-12-31 +0001520006 +mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember +2019-12-31 +0001520006 +mtdr:NaturalGasTransportationandFractionationAgreementMember +mtdr:EddyCountyMember +2019-12-31 +0001520006 +mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember +mtdr:EddyCountyMember +2019-10-31 +0001520006 +mtdr:EngineeringProcurementConstructionAndInstallationOfProcessingPlantMember +mtdr:SanMateoMidstreamMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2019-12-31 +0001520006 +mtdr:EngineeringProcurementConstructionAndInstallationOfProcessingPlantMember +mtdr:SanMateoMidstreamMember +2019-12-31 +0001520006 +mtdr:ShortTermDrillingRigCommitmentsMember +2019-12-31 +0001520006 +mtdr:DrillingRigCommitmentsMember +2019-12-31 +0001520006 +mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember +2018-01-01 +2018-12-31 +0001520006 +mtdr:OperationalAgreementsMember +mtdr:SanMateoMidstreamMember +2019-02-25 +0001520006 +mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:NaturalGasTransportationAgreementMember +2019-10-01 +2019-10-31 +0001520006 +mtdr:NaturalGasTransportationandFractionationAgreementMember +mtdr:EddyCountyMember +2019-01-01 +2019-12-31 +0001520006 +mtdr:AccruedPartnersShareOfJointInterestChargesMember +2019-12-31 +0001520006 +mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember +2018-12-31 +0001520006 +mtdr:AccruedLeaseOperatingExpensesMember +2018-12-31 +0001520006 +mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember +2019-12-31 +0001520006 +mtdr:AccruedLeaseOperatingExpensesMember +2019-12-31 +0001520006 +mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember +2019-12-31 +0001520006 +mtdr:AccruedAssetRetirementObligationsMember +2018-12-31 +0001520006 +mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember +2019-12-31 +0001520006 +mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember +2018-12-31 +0001520006 +mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember +2018-12-31 +0001520006 +mtdr:AccruedPartnersShareOfJointInterestChargesMember +2018-12-31 +0001520006 +mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember +2019-12-31 +0001520006 +mtdr:AccruedAssetRetirementObligationsMember +2019-12-31 +0001520006 +mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:ExplorationandProductionSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:ExplorationandProductionSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:MidstreamSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:ExplorationandProductionSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:MidstreamSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:MidstreamSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:ExplorationandProductionSegmentMember +2019-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +mtdr:NaturalGasSalesMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:NaturalGasSalesMember +mtdr:MidstreamSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:NaturalGasMidstreamMember +mtdr:MidstreamSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +us-gaap:OilAndGasMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:MidstreamSegmentMember +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:OilAndGasMember +mtdr:ExplorationandProductionSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +mtdr:NaturalGasSalesMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:NaturalGasSalesMember +mtdr:ExplorationandProductionSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +us-gaap:OilAndGasMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:NaturalGasMidstreamMember +mtdr:ExplorationandProductionSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +us-gaap:NaturalGasMidstreamMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:OilAndGasMember +mtdr:MidstreamSegmentMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +us-gaap:NaturalGasMidstreamMember +2019-01-01 +2019-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +2019-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:MidstreamSegmentMember +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:NaturalGasSalesMember +mtdr:MidstreamSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +us-gaap:OilAndGasMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +us-gaap:NaturalGasMidstreamMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:NaturalGasMidstreamMember +mtdr:MidstreamSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +us-gaap:NaturalGasMidstreamMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +2018-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:NaturalGasMidstreamMember +mtdr:ExplorationandProductionSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +us-gaap:OilAndGasMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +mtdr:NaturalGasSalesMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:OilAndGasMember +mtdr:ExplorationandProductionSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +mtdr:NaturalGasSalesMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:NaturalGasSalesMember +mtdr:ExplorationandProductionSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:OilAndGasMember +mtdr:MidstreamSegmentMember +2018-01-01 +2018-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:ExplorationandProductionSegmentMember +2018-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:OilAndGasMember +mtdr:MidstreamSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +us-gaap:NaturalGasMidstreamMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:OilAndGasMember +mtdr:ExplorationandProductionSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +us-gaap:OilAndGasMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:NaturalGasMidstreamMember +mtdr:MidstreamSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:ExplorationandProductionSegmentMember +2017-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +us-gaap:OilAndGasMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +mtdr:MidstreamSegmentMember +2017-12-31 +0001520006 +us-gaap:IntersegmentEliminationMember +2017-12-31 +0001520006 +us-gaap:OperatingSegmentsMember +us-gaap:NaturalGasMidstreamMember +mtdr:ExplorationandProductionSegmentMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +us-gaap:NaturalGasMidstreamMember +2017-01-01 +2017-12-31 +0001520006 +us-gaap:CorporateNonSegmentMember +2017-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2019-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2019-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2019-01-01 +2019-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2019-01-01 +2019-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2019-01-01 +2019-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2018-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2019-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2019-01-01 +2019-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2018-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2018-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2018-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2019-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2018-01-01 +2018-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2018-01-01 +2018-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2018-01-01 +2018-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2018-01-01 +2018-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2017-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2017-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2017-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2017-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2017-01-01 +2017-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2017-01-01 +2017-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2017-01-01 +2017-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2017-01-01 +2017-12-31 +0001520006 +srt:NonGuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2016-12-31 +0001520006 +srt:ConsolidationEliminationsMember +2016-12-31 +0001520006 +srt:ParentCompanyMember +srt:ReportableLegalEntitiesMember +2016-12-31 +0001520006 +srt:GuarantorSubsidiariesMember +srt:ReportableLegalEntitiesMember +2016-12-31 +0001520006 +mtdr:SanMateoMidstreamMember +us-gaap:CorporateJointVentureMember +2018-01-01 +2018-09-30 +xbrli:shares +iso4217:USD +utreg:MMBTU +iso4217:USD +utreg:bbl +mtdr:Purchasers +iso4217:USD +xbrli:shares +xbrli:pure +iso4217:USD +utreg:acre +utreg:bbl +mtdr:well +mtdr:segment +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2019 +or +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-35410 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas +27-4662601 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +5400 LBJ Freeway, +Suite 1500 +75240 +Dallas, +Texas +(Address of principal executive offices) +(Zip Code) +( 972 ) 371-5200 +(Registrant’s telephone number, including area code) +_________________________________________________________ +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Trading symbol(s) +Name of each exchange on which registered +Common Stock, par value $0.01 per share +MTDR +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ☒ No ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +☒ +Accelerated filer +☐ +Non-accelerated filer +☐ +Smaller reporting company +☐ +Emerging growth company +☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ☐ No ☒ +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $ 2,187,634,344 . +As of February 28, 2020 , there were 116,569,389 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2020 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +32 +I TEM 1B. +Unresolved Staff Comments +60 +I TEM 2. +Properties +60 +I TEM 3. +Legal Proceedings +60 +I TEM 4. +Mine Safety Disclosures +60 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +61 +I TEM 6. +Selected Financial Data +64 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +66 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +84 +I TEM 8. +Financial Statements and Supplementary Data +86 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +86 +I TEM 9A. +Controls and Procedures +86 +I TEM 9B. +Other Information +89 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +89 +I TEM 11. +Executive Compensation +89 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +89 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +89 +I TEM 14. +Principal Accounting Fees and Services +89 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +90 +ITEM 16. +Form 10-K Summary +90 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; availability of sufficient capital to execute our business plan, including from future cash flows, increases in our borrowing base and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the operating results of our midstream joint venture’s expansion of the Black River cryogenic natural gas processing plant, including the timing of the further expansion of such plant; the timing and operating results of the buildout by our midstream joint venture of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells, including in conjunction with the expansion of our midstream joint venture’s services and assets into new areas in Eddy County, New Mexico ; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• +our business strategy; +• +our estimated future reserves and the present value thereof; +• +our cash flows and liquidity; +• +our financial strategy, budget, projections and operating results; +• +our oil and natural gas realized prices; +• +the timing and amount of future production of oil and natural gas; +• +the availability of drilling and production equipment; +• +the availability of oil field labor; +• +the amount, nature and timing of capital expenditures, including future exploration and development costs; +• +the availability and terms of capital; +• +our drilling of wells; +• +our ability to negotiate and consummate acquisition and divestiture opportunities; +• +government regulation and taxation of the oil and natural gas industry; +• +our marketing of oil and natural gas; +• +our exploitation projects or property acquisitions; +• +the integration of acquisitions with our business; +• +our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the operation and expansion of our Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; +• +the ability of our midstream joint venture to attract third-party volumes; +• +our costs of exploiting and developing our properties and conducting other operations; +• +general economic conditions; +• +competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• +the effectiveness of our risk management and hedging activities; +• +our technology; +• +environmental liabilities; +• +counterparty credit risk; +• +developments in oil-producing and natural gas-producing countries; +• +our future operating results; and +• +our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +1 +Table of Contents +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC (“San Mateo I”) together with San Mateo Midstream II, LLC (“San Mateo II”). For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2019 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also improved the capital efficiency of our drilling and completion operations and continued to improve our leasehold and minerals position in the Delaware Basin. In addition, we concluded several important financing transactions in 2019, including an +2 +Table of Contents +increase in the borrowing base under our Credit Agreement (as defined below), two increases in the lender commitments under the San Mateo Credit Facility (as defined below) and the conversion of approximately $21.9 million of non-core assets to cash. San Mateo also achieved several important milestones in 2019, including the formation of San Mateo II, an increased natural gas gathering and processing commitment from an existing natural gas customer, significant additional acreage dedications from existing salt water disposal customers, an acreage dedication from a new oil customer and an increase in designed salt water disposal capacity. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2019 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2019 , we achieved record oil, natural gas and average daily oil equivalent production. In 2019 , we produced 14.0 million Bbl of oil, an increase of 26% , as compared to 11.1 million Bbl of oil produced in 2018 . We also produced 61.1 Bcf of natural gas, an increase of 29% from 47.3 Bcf of natural gas produced in 2018 . Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, an increase of 27% , as compared to 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, for the year ended December 31, 2018 . The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2019 , as compared to 59% for the year ended December 31, 2018 . +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2019 , our estimated total proved oil and natural gas reserves were 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, an increase of 17% from 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, at December 31, 2018 . The Standardized Measure of our total proved oil and natural gas reserves decrease d 10% from $2.25 billion at December 31, 2018 to $2.03 billion at December 31, 2019 . The PV-10 of our total proved oil and natural gas reserves decrease d 13% from $2.58 billion at December 31, 2018 to $2.25 billion at December 31, 2019 . The decreases in our Standardized Measure and PV-10 were primarily a result of lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2019 , as compared to December 31, 2018 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 20% to 148.0 million Bbl at December 31, 2019 from 123.4 million Bbl at December 31, 2018 . Our proved natural gas reserves increase d 14% to 627.2 Bcf at December 31, 2019 from 551.5 Bcf at December 31, 2018 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2019 . +At December 31, 2019 , proved developed reserves included 59.7 million Bbl of oil and 276.3 Bcf of natural gas, and proved undeveloped reserves included 88.3 million Bbl of oil and 351.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 42% and 59% , respectively, of our total proved oil and natural gas reserves at December 31, 2019 . Proved developed reserves and proved oil reserves comprised 44% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2018 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past six years. We expect the Delaware Basin will continue to be our primary area of focus in 2020 . +3 +Table of Contents +We completed and began producing oil and natural gas from 138 gross (65.7 net) wells in the Delaware Basin in 2019 , including 76 gross (61.4 net) operated and 62 gross (4.3 net) non-operated wells. At December 31, 2019 , our total acreage position in the Delaware Basin was approximately 231,300 gross ( 128,200 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on the following asset areas: the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increase d approximately 23% to 55,599 BOE per day ( 84% of total oil equivalent production), including 35,184 Bbl of oil per day ( 92% of total oil production) and 122.5 MMcf of natural gas per day ( 73% of total natural gas production), in 2019 , as compared to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 . We expect our Delaware Basin production to increase in 2020 as we continue the delineation and development of these asset areas, as well as our new Stateline asset area in Eddy County, New Mexico, where we expect to begin production late in the third quarter of 2020. +Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2019 included: +• +in our Rustler Breaks asset area, the results from our first two operated First Bone Spring tests, including the Garrett State Com 32-24S-29E RB #111H (Garrett #111H) well and the Paul 25-24S-28E RB #111H (Paul #111H) well, demonstrating the prospectivity of this formation and the continued delineation and development of previously tested horizons; +• +in our Wolf asset area, the continuing success from several wells with longer laterals (greater than one mile) drilled and completed in the Wolfcamp A-XY interval; +• +in our Jackson Trust asset area, the continued development of the Wolfcamp A-Lower interval; +• +in our Arrowhead and Ranger asset areas, the results from our Wolfcamp A-XY completions, particularly in the Stebbins acreage block in the Arrowhead asset area, whose 24-hour initial potential (“IP”) test results and subsequent well performance demonstrate the prospectivity of the Wolfcamp formation moving north in the Delaware Basin; +• +in our Antelope Ridge asset area, the results from the Jeff Hart State Com #124H and #134H (Jeff Hart #124H and #134H) wells, our first two operated two-mile horizontal wells in the asset area, and the initiation of drilling operations on six wells in the western region of the asset area (the “Rodney Robinson” wells); +• +in our Stateline asset area, the successful approval and receipt of 14 drilling permits from the Bureau of Land Management (“BLM”) and the initiation of drilling operations there in late December 2019; +• +the transition to drilling longer laterals, whereby 29% of the operated horizontal wells we completed and turned to sales in 2019 had lateral lengths greater than one mile, as compared to 9% in 2018; +• +the continuing improvement in capital efficiency as demonstrated by our average drilling and completion costs for all operated horizontal wells completed and turned to sales of approximately $1,165 per lateral foot in 2019, a decrease of 24% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018; +• +the initial transportation of much of our Delaware Basin residue natural gas production to the Texas Gulf Coast on the newly commissioned Gulf Coast Express Pipeline Project (the “GCX Pipeline”) beginning in late September 2019; and +• +the significant progress made in our midstream operations, including (i) strong operating results in 2019, (ii) the initiation of an expansion of San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) by an additional 200 MMcf per day of designed natural gas processing inlet capacity, which is anticipated to be placed in service during the summer of 2020, (iii) the initiation of San Mateo’s plans to construct large diameter natural gas gathering lines southward from the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and northward from the Stateline asset area to connect these areas with the Black River Processing Plant, (iv) the addition of significant salt water disposal capacity in the Rustler Breaks asset area and the Greater Stebbins Area and (v) the progress made by San Mateo in increasing commitments, throughput volumes and acreage dedications from both new and existing customers. +We also concluded operations on our nine-well program in South Texas (initiated in late 2018) during the second quarter of 2019 , which included turning to sales seven gross (6.9 net) wells in the Eagle Ford formation and one gross (1.0 net) well in the Austin Chalk formation in 2019 . We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019 , although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that began producing in 2019 , including two highly productive two-mile lateral wells completed and turned to sales by an affiliate of Chesapeake Energy Corporation (“Chesapeake”) during the third quarter of 2019. +4 +Table of Contents +Financing Transactions +We concluded several important financing transactions in 2019 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• +the amendment of our third amended and restated credit agreement (the “Credit Agreement”) to increase the borrowing base to $900.0 million, which was further amended in February 2020 to increase our elected borrowing commitment from $500.0 million to $700.0 million; +• +the increase of the lender commitments under San Mateo I’s credit facility (the “San Mateo Credit Facility”) to $375.0 million, using the accordion feature; and +• +the conversion of approximately $21.9 million of non-core assets to cash during 2019. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. As part of this transaction, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. In addition, Five Point has committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. Five Point has also provided us the opportunity to earn deferred performance incentives of up to $150.0 million over the next several years as we execute our operational plans in and around the Greater Stebbins Area and the Stateline asset area, plus additional performance incentives for securing volumes from third-party customers. +San Mateo achieved strong operating results in 2019, highlighted by (i) increased third-party midstream services revenues, (ii) increased natural gas gathering and processing volumes, (iii) increased water gathering and water disposal volumes and (iv) increased oil gathering volumes, all as compared to 2018. San Mateo initiated construction on an additional 200 MMcf per day of designed natural gas processing inlet capacity as part of the expansion of the Black River Processing Plant, which is anticipated to be placed in service during the summer of 2020 and would bring the total designed inlet capacity of the Black River Processing Plant to 460 MMcf of natural gas per day. San Mateo also initiated plans to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. During 2019, San Mateo added four commercial salt water disposal wells, two in the Rustler Breaks asset area and two in the Greater Stebbins Area, and expects to place into service one additional commercial salt water disposal well in the Rustler Breaks asset area in the first quarter of 2020, bringing San Mateo’s designed salt water disposal capacity to approximately 335,000 Bbl per day. +During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes, obtained significant additional acreage dedications from existing salt water customers and added an acreage dedication from a new oil customer. At certain times near the end of the third quarter and early in the fourth quarter of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day. +Environmental, Social and Governance (“ESG”) Initiatives +We maintain an active ESG program and continued working in 2019 to improve upon our various ESG efforts. For instance, we significantly increased the number of our production facilities operating on electrical grid power, lowering emissions by removing on-site generators. We increased the volumes of produced water we recycled in the Delaware Basin as well as the volumes of both produced water and oil transported via pipeline, taking trucks off the roads. We also reduced the number of well pads built in 2019 through our use of batch drilling and longer laterals, reducing our surface footprint. Finally, we continued our commitment to a proactive safety culture, with over 1.4 million employee man-hours and no lost time accidents since 2017. +5 +Table of Contents +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2019 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2019 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +231,300 +128,200 +757 +354.0 +5,287 +2,332.4 +232,793 +39.0 +55,599 +South Texas: +Eagle Ford (5) +31,200 +28,400 +143 +121.4 +234 +196.3 +11,219 +65.5 +4,009 +Northwest Louisiana +Haynesville +17,500 +10,000 +246 +20.5 +341 +80.8 +7,652 +86.3 +6,345 +Cotton Valley (6) +16,100 +14,900 +66 +40.7 +70 +48.3 +866 +100.0 +250 +Area Total (7) +19,700 +18,300 +312 +61.2 +411 +129.1 +8,518 +87.7 +6,595 +Total +282,200 +174,900 +1,212 +536.6 +5,932 +2,657.8 +252,530 +41.9 +66,203 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2019 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Each horizontal drilling location generally represents a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. At December 31, 2019 , these engineered drilling locations included only 372 gross (168.5 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon, Delaware and Strawn formations, in the Delaware Basin, 14 gross (13.7 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and five gross (0.5 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. Certain of these locations to which we have assigned proved undeveloped reserves may contemplate lateral lengths longer than one mile. +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2019 . +(5) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2019 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2019 , we also were the operator for approximately 93% of our Eagle Ford acreage and approximately 59% of our Haynesville acreage, including approximately 26% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent +6 +Table of Contents +reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2019 , our total acreage position in Southeast New Mexico and West Texas was approximately 231,300 gross ( 128,200 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 36,400 gross (19,500 net) acres in our Ranger asset area in Lea County, 61,900 gross (26,300 net) acres in our Arrowhead asset area in Eddy County, 44,000 gross (25,000 net) acres in our Rustler Breaks asset area in Eddy County, 24,200 gross (16,500 net) acres in our Antelope Ridge asset area in Lea County, 15,000 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our Stateline asset area in Eddy County and 46,400 gross (26,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2019 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2019 , our acreage position in the Delaware Basin was approximately 59% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the BLM New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 73% held by existing production at December 31, 2019 . +During the year ended December 31, 2019 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 138 gross (65.7 net) wells in the Delaware Basin, including 76 gross (61.4 net) operated wells and 62 gross (4.3 net) non-operated wells, throughout our various asset areas. At December 31, 2019 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, the Avalon, the First Bone Spring, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2019 . Our average daily oil equivalent production from the Delaware Basin increase d approximately 23% to 55,599 BOE per day ( 84% of total oil equivalent production), including 35,184 Bbl of oil per day ( 92% of total oil production) and 122.5 MMcf of natural gas per day ( 73% of total natural gas production), in 2019 , as compared to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 . Our average daily oil equivalent production from the Delaware Basin also grew approximately 25% from 49,309 BOE per day in the fourth quarter of 2018 to 61,493 BOE per day in the fourth quarter of 2019 . +At December 31, 2019 , approximately 92% of our estimated total proved oil and natural gas reserves, or 232.8 million BOE, was attributable to the Delaware Basin, including approximately 139.6 million Bbl of oil and 559.2 Bcf of natural gas, a 22% increase, as compared to 191.5 million BOE for the year ended December 31, 2018 . Our Delaware Basin proved reserves +7 +Table of Contents +at December 31, 2019 comprised approximately 94% of our proved oil reserves and 89% of our proved natural gas reserves, as compared to approximately 93% of our proved oil reserves and 83% of our proved natural gas reserves at December 31, 2018 . +At December 31, 2019 , we had identified 5,287 gross ( 2,332.4 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 3,290 gross (2,139.7 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Each horizontal drilling location generally represents a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2019 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2019 , the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2019 , these potential future drilling locations included 372 gross (168.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon, Delaware and Strawn formations, to which we have assigned proved undeveloped reserves, and certain of these locations to which we have assigned proved undeveloped reserves may contemplate lateral lengths longer than one mile. +At December 31, 2019 , we were operating six drilling rigs in the Delaware Basin, and we expect to operate six rigs in the Delaware Basin throughout 2020 , including two to four rigs (at times) in the Stateline asset area, one to two rigs (at times) in the Rustler Breaks asset area, one to two rigs (at times) in the Antelope Ridge asset area, one rig in the Wolf and Jackson Trust asset areas and one rig in the Greater Stebbins Area in the southern Arrowhead asset area. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 19 months. The other three rigs are on short-term contracts with remaining obligations of less than twelve months. This affords us the ability to modify our drilling program as we may deem necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2020 . +Rustler Breaks Asset Area - Eddy County, New Mexico +We operated one to two drilling rigs in our Rustler Breaks asset area during most of 2019 . We completed and turned to sales 48 gross (16.7 net) horizontal wells and one gross (1.0 net) vertical well in the Rustler Breaks asset area in 2019, including 19 gross (14.4 net) operated and 30 gross (3.3 net) non-operated wells. +The Garrett #111H well was particularly significant, being our first operated test of the First Bone Spring formation in the Rustler Breaks asset area. This well, a one-mile lateral, tested 2,042 BOE per day (75% oil) during a 24-hour IP test in the third quarter of 2019. A second operated test of the First Bone Spring in the fourth quarter of 2019, the Paul #111H, tested 1,793 BOE per day (81% oil) during a 24-hour IP test. We believe these two wells demonstrate the prospectivity of the First Bone Spring formation in the Rustler Breaks asset area. +We were also pleased with the results from our Wolfcamp wells turned to sales in 2019 in the Rustler Breaks asset area. In particular, the General Kehoe wells in the eastern portion of the asset area were drilled and completed as part of a five-well batch from a single pad and contributed significantly to our better-than-expected oil and natural gas production in the second half of 2019. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY and Wolfcamp A-Lower formations in 2019. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2019, and we completed and turned to sales 11 gross (7.8 net) horizontal wells in these asset areas, including ten gross (7.8 net) operated wells and one gross (less than 0.1 net) non-operated well. Most of these wells were completed in the Wolfcamp A-XY interval. +We continued to experience success with longer laterals (greater than one mile) we drilled in the Wolf asset area in 2019. For example, the Howard Posner 83-TTT-B33 WF #203H and #204H (Howard Posner #203H and #204H) wells, both Wolfcamp A-XY completions, tested 2,382 BOE per day (58% oil) and 1,813 BOE per day (60% oil), respectively, during 24-hour IP tests. Both the Howard Posner #203H and #204H wells had completed lateral lengths of approximately 7,500 feet. +8 +Table of Contents +Arrowhead, Ranger and Twin Lakes Asset Areas - Eddy and Lea Counties, New Mexico +We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2019. We completed and turned to sales 20 gross (11.3 net) horizontal wells and two gross (2.0 net) vertical wells in the Arrowhead, Ranger and Twin Lakes asset areas in 2019, including 17 gross (13.0 net) operated and five gross (0.3 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals. +Following our initial test of the Wolfcamp A-XY in the third quarter of 2018, we were pleased with our continued delineation of the Wolfcamp A-XY in the Arrowhead asset area in 2019. In the third quarter of 2019, we completed and placed on production the Stebbins 19 Federal Com #203H and #204H wells. These wells tested 2,815 BOE per day (73% oil) and 2,262 BOE per day (75% oil), respectively, during 24-hour IP tests. We believe these results provided further evidence of Wolfcamp A-XY prospectivity moving north in the Delaware Basin. +Antelope Ridge Asset Area - Lea County, New Mexico +We operated one to two drilling rigs in our Antelope Ridge asset area during 2019 . We completed and turned to sales 55 gross (25.9 net) horizontal wells and one gross (1.0 net) vertical well in this asset area in 2019 , including 30 gross (26.2 net) operated and 26 gross (0.7 net) non-operated wells. As we continued to delineate the Antelope Ridge asset area during 2019, we tested six different intervals, completing wells in the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower. +A key achievement in our Antelope Ridge asset area in 2019 was the drilling and completion of our first two operated two-mile horizontal wells in the asset area—the Jeff Hart #124H and #134H wells, Second Bone Spring and Third Bone Spring completions, respectively. The Jeff Hart #124H and #134H wells tested 2,332 BOE per day (81% oil) and 2,884 BOE per day (90% oil), respectively, during 24-hour IP tests in the third quarter of 2019. The Jeff Hart #134H well produced approximately 70,000 Bbl of oil in its first 30 days of production, which is the highest 30-day cumulative oil production for any well drilled and completed by us, including our prolific Mallon wells in the Ranger asset area, also Third Bone Spring completions. Further, drilling and completion costs on the Jeff Hart #134H well were just under $1,000 per lateral foot, about 20% to 25% below the drilling and completion costs per lateral foot associated with one-mile laterals we previously drilled in the Antelope Ridge asset area. In their first five months of production, the Jeff Hart #124H and #134H wells each produced more than 200,000 Bbl of oil in its first 150 days of production. The early production from these wells has more than doubled that of our nearby one-mile lateral completions over a similar timeframe, and these wells continued to exhibit a shallower initial production decline as compared to nearby one-mile laterals drilled by us. +In addition, we were particularly pleased with our delineation of the Wolfcamp A formation in the Antelope Ridge asset area. The Brad Lummis Com #212H well, a Wolfcamp A-XY completion, flowed at 3,236 BOE per day (83% oil) during its 24-hour IP test, or over 700 BOE per 1,000 feet of completed lateral. This well result complemented those from the four Charles Ling wells completed and turned to sales in the Wolfcamp A-Lower formation late in the first quarter of 2019, which flowed at an average of 2,932 BOE per day (75% oil) during their respective 24-hour IP tests. +Additionally, we began drilling operations on the 1,200 gross and net acre Rodney Robinson tract in our western Antelope Ridge asset area in the third quarter of 2019. The Rodney Robinson tract is one of the key tracts we acquired in the BLM Acquisition. The acquired leases are federal leases and provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. We drilled six initial wells on this tract from two separate three-well pads. These six wells, which are all two-mile laterals, are currently scheduled to be completed and turned to sales in late March 2020. +9 +Table of Contents +Stateline Asset Area - Eddy County, New Mexico +In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net undeveloped leasehold acres prospective for multiple geologic targets. The acquired leases are federal leases and provide an 87.5% NRI. The large majority of the acquired acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We began drilling operations in the Stateline asset area just before the end of 2019 and, at February 25, 2020, had two of our drilling rigs operating there. We plan to develop this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.5-mile laterals on the western side of the leasehold. We initially expect to drill 13 wells on the eastern portion of this leasehold, and these 13 wells are expected to be completed and turned to sales late in third quarter of 2020 in conjunction with the expected completion of the expansion of the Black River Processing Plant by San Mateo. We anticipate running at least two rigs full-time in the Stateline asset area for the foreseeable future. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2019 , our properties included approximately 31,200 gross ( 28,400 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 93% of our Eagle Ford acreage was held by production at December 31, 2019 . +In October 2018, we commenced a drilling program in South Texas to drill nine wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and hold by production almost all of our remaining undeveloped acreage in South Texas. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight gross (7.9 net) wells, including one well drilled in the Austin Chalk formation, were completed and turned to sales in the first half of 2019. +Two of these wells, the Lloyd Hurt C #12H and D #13H wells, which targeted the Eagle Ford shale, flowed an average of 1,085 BOE per day (85% oil), including 923 Bbl of oil per day and 1.0 MMcf of natural gas per day, during 24-hour IP tests from completed lateral lengths of approximately 8,800 feet. These wells marked the two best 24-hour IP test results from any Eagle Ford wells we have completed to date in our far northwest La Salle County acreage. In addition, the Lloyd Hurt AC-C #26H well, an Austin Chalk completion, tested approximately 600 BOE per day (93% oil) during a 24-hour IP test conducted following the installation of an electric submersible pump (“ESP”) in the wellbore. We were encouraged by this initial test and the early results from the Austin Chalk formation in far northwest La Salle County, where almost no horizontal completions of the Austin Chalk formation using modern drilling and stimulation technology had been previously attempted. +Primarily as a result of the initial production from this nine-well program, our average daily oil equivalent production from the Eagle Ford shale increase d 27% to 4,009 BOE per day, including 3,113 Bbl of oil per day and 5.4 MMcf of natural gas per day, during 2019 , as compared to 3,158 BOE per day, including 2,485 Bbl of oil per day and 4.0 MMcf of natural gas per day, during 2018 . For the year ended December 31, 2019 , 6% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 6% for the year ended December 31, 2018 . +At December 31, 2019 , approximately 4% of our estimated total proved oil and natural gas reserves, or 11.2 million BOE, was attributable to the Eagle Ford shale, including approximately 8.4 million Bbl of oil and 17.2 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 6% of our proved oil reserves and 3% of our proved natural gas reserves at December 31, 2019 , as compared to approximately 7% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2018 . +At December 31, 2019 , we had identified 234 gross ( 196.3 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by +10 +Table of Contents +regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2019 , these 234 gross ( 196.3 net) identified drilling locations included 14 gross (13.7 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2019 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019 , although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that were turned to sales in 2019 , the most significant of which were two gross (1.0 net) two-mile lateral wells drilled and completed by Chesapeake in the third quarter of 2019. These two wells, the LDW&F 15&10-14-12 HC001-ALT and HC002-ALT wells, were located in the southern part of our Elm Grove asset area in the core of the Haynesville shale play and tested 38.4 and 42.4 MMcf of natural gas per day, respectively, during 24-hour IP tests, and these wells contributed to our natural gas production growth in the second half of 2019. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2020 . +At December 31, 2019 , we held approximately 19,700 gross ( 18,300 net) acres in Northwest Louisiana, including 17,500 gross ( 10,000 net) acres in the Haynesville shale play and 16,100 gross ( 14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 26% of the 12,400 gross ( 5,600 net) acres that we consider to be in the core area of the Haynesville shale play. +For the year ended December 31, 2019 , approximately 10% of our average daily oil equivalent production, or 6,595 BOE per day, including 15 Bbl of oil per day and 39.5 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana. Natural gas production from these properties comprised approximately 24% of our daily natural gas production during 2019 , as compared to approximately 17% of our daily natural gas production during 2018 . During the year ended December 31, 2018 , approximately 7% of our average daily oil equivalent production, or 3,733 BOE per day, including 13 Bbl of oil per day and 22.3 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2019 , approximately 23% of our daily natural gas production, or 38.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1% , or 1.4 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2018 , approximately 16% of our daily natural gas production, or 20.5 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1% , or 1.8 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2019 , approximately 3% of our estimated total proved reserves, or 7.7 million BOE, was attributable to the Haynesville shale with another 0.3% of our proved reserves, or 0.9 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2019 , we had identified 341 gross ( 80.8 net) engineered locations for potential future drilling in the Haynesville shale play and 70 gross ( 48.3 net) engineered locations for potential future drilling in the Cotton Valley formation. Each horizontal drilling location generally assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into +11 +Table of Contents +account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 341 gross ( 80.8 net) locations identified for future drilling on our Haynesville acreage, 277 gross (37.8 net) locations have been identified within the 12,400 gross ( 5,600 net) acres that we believe are located in the core area of the Haynesville shale play. As we explore and develop our Northwest Louisiana acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2019 , these potential future drilling locations included 5 gross (0.5 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo I, a strategic joint venture with a subsidiary of Five Point. The midstream assets that were contributed to San Mateo I included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo I and had the potential to earn up to $73.5 million in performance incentives over a five-year period. At February 28, 2020, we had received $44.1 million of the potential $73.5 million in performance incentives. We may earn up to the remaining $29.4 million in San Mateo I performance incentives over the next two years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo I. The Company and Five Point own 51% and 49% of San Mateo I, respectively. San Mateo I continues to provide firm service to us, while also being a midstream service provider to other customers in and around our Wolf and Rustler Breaks asset areas. +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. In addition, Five Point has committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. We have the ability to earn up to $150.0 million in deferred performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. +In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. San Mateo II provides firm service to us in the Greater Stebbins Area and the Stateline asset area. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During 2019, as part of the San Mateo II expansion, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. This expansion is anticipated to be placed in service during the summer of 2020. In addition, San Mateo initiated plans in 2019 to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. The expanded Black River Processing Plant supports our exploration and production development activities in the Delaware Basin and offers processing opportunities for other producers’ development efforts. +During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes. At certain times near the end of the third quarter and early in the fourth quarter +12 +Table of Contents +of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day. +In October 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including us, at December 31, 2019 , San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant. +In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs and (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connected our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo I in February 2017. +At December 31, 2019 , San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2019 , San Mateo gathered approximately 77.2 Bcf of natural gas, as compared to 46.1 Bcf of natural gas gathered during the year ended December 31, 2018 . In addition, during the year ended December 31, 2019 , San Mateo processed approximately 64.7 Bcf of natural gas at the Black River Processing Plant, as compared to 32.3 Bcf of natural gas processed during the year ended December 31, 2018 . +Crude Oil Gathering and Transportation Assets +Subsidiaries of San Mateo and Plains All American Pipeline, L.P. (“Plains”) have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +San Mateo completed its expanded oil gathering system in the Wolf asset area in Loving County, Texas (the “Wolf Oil Pipeline System”) in May 2018 and placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) in December 2018. With the Wolf Oil Pipeline System and the Rustler Breaks Oil Pipeline System (collectively, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2019 , we estimated we had on pipe almost all of our oil production from the Wolf and Rustler Breaks asset areas, which comprised approximately 56% of our Delaware Basin oil production in 2019. With the San Mateo Oil Pipeline Systems in service, we improved our oil price realizations in the Wolf and Rustler Breaks asset areas through the elimination of higher priced trucking services. +At December 31, 2019 , the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from origin points in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains Pipeline, L.P. and two trucking facilities. During the year ended December 31, 2019 , the San Mateo Oil Pipeline Systems had throughput of approximately 8.9 million Bbl of oil, as compared to 2.0 million Bbl of oil throughput during the year ended December 31, 2018 . +Produced Water Gathering and Disposal Assets +During 2019, San Mateo placed into service two commercial salt water disposal wells in the Rustler Breaks asset area and, at February 25, 2020 , expected to place into service one additional salt water disposal well in the Rustler Breaks asset area late in the first quarter of 2020, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to eight. In the Greater Stebbins Area, San Mateo also acquired an existing commercial salt water disposal well and facility and surface acreage and subsequently placed into service an additional commercial salt water disposal well. In addition to its eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area and its two commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 25, 2020 , San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, and San Mateo’s salt water gathering systems included salt +13 +Table of Contents +water gathering pipelines in the Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 25, 2020 , San Mateo expected to have a designed disposal capacity of approximately 335,000 Bbl of salt water per day by the end of the first quarter of 2020. +In June 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. In the first half of 2019, San Mateo obtained a significant additional acreage dedication and a salt water disposal well permit from another existing salt water disposal customer. +During the year ended December 31, 2019 , San Mateo gathered approximately 69.9 million Bbl of salt water, as compared to 44.0 million Bbl of salt water gathered during the year ended December 31, 2018 . In addition, during the year ended December 31, 2019 , San Mateo disposed of approximately 67.1 million Bbl of salt water, as compared to 47.5 million Bbl of salt water disposed of during the year ended December 31, 2018 . +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather and treat natural gas from most of our operated leases and from third parties and four non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2019, 2018 and 2017 . +Year Ended December 31, +2019 +2018 +2017 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +13,984 +11,141 +7,851 +Natural gas (Bcf) +61.1 +47.3 +38.2 +Total oil equivalent (MBOE) (1) +24,164 +19,026 +14,212 +Average daily production (BOE/d) (1) +66,203 +52,128 +38,936 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +54.34 +$ +57.04 +$ +49.28 +Oil, with realized derivatives (per Bbl) +$ +54.98 +$ +57.38 +$ +48.81 +Natural gas, without realized derivatives (per Mcf) +$ +2.17 +$ +3.49 +$ +3.72 +Natural gas, with realized derivatives (per Mcf) +$ +2.18 +$ +3.46 +$ +3.70 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +3.82 +$ +4.00 +$ +4.10 +Lease operating +$ +4.85 +$ +4.89 +$ +4.74 +Plant and other midstream services operating +$ +1.52 +$ +1.29 +$ +0.92 +Depletion, depreciation and amortization +$ +14.51 +$ +13.94 +$ +12.49 +General and administrative +$ +3.31 +$ +3.64 +$ +4.65 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +12,843 +1,136 +— +5 +13,984 +Natural gas (Bcf) +44.7 +2.0 +13.9 +0.5 +61.1 +Total oil equivalent (MBOE) (3) +20,294 +1,463 +2,316 +91 +24,164 +Percentage of total annual net production +84.0 +% +6.0 +% +9.6 +% +0.4 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +35,184 +3,113 +— +15 +38,312 +Natural gas (MMcf/d) +122.5 +5.4 +38.1 +1.4 +167.4 +Total oil equivalent (BOE/d) +55,599 +4,009 +6,345 +250 +66,203 +Average Sales Prices (4) +Oil (per Bbl) +$ +53.95 +$ +58.71 +$ +— +$ +52.89 +$ +54.34 +Natural gas (per Mcf) +$ +2.11 +$ +3.45 +$ +2.16 +$ +2.17 +$ +2.17 +Total oil equivalent (per BOE) +$ +38.80 +$ +50.22 +$ +12.99 +$ +15.22 +$ +36.93 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.22 +$ +15.27 +$ +4.36 +$ +22.43 +$ +5.81 +__________________ +(1) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +10,230 +907 +— +4 +11,141 +Natural gas (Bcf) +37.7 +1.5 +7.5 +0.6 +47.3 +Total oil equivalent (MBOE) (3) +16,512 +1,152 +1,247 +115 +19,026 +Percentage of total annual net production +86.8 +% +6.0 +% +6.6 +% +0.6 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +28,026 +2,485 +— +13 +30,524 +Natural gas (MMcf/d) +103.3 +4.0 +20.5 +1.8 +129.6 +Total oil equivalent (BOE/d) +45,237 +3,158 +3,417 +316 +52,128 +Average Sales Prices (4) +Oil (per Bbl) +$ +56.12 +$ +67.4 +$ +— +$ +64.72 +$ +57.04 +Natural gas (per Mcf) +$ +3.55 +$ +5.46 +$ +2.85 +$ +2.80 +$ +3.49 +Total oil equivalent (per BOE) +$ +42.88 +$ +60.02 +$ +17.09 +$ +18.59 +$ +42.08 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +4.79 +$ +17.25 +$ +5.41 +$ +19.11 +$ +5.68 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +16 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +6,579 +1,268 +— +4 +7,851 +Natural gas (Bcf) +25.1 +2.0 +10.3 +0.8 +38.2 +Total oil equivalent (MBOE) (3) +10,754 +1,611 +1,714 +133 +14,212 +Percentage of total annual net production +75.7 +% +11.3 +% +12.1 +% +0.9 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +18,023 +3,475 +— +12 +21,510 +Natural gas (MMcf/d) +68.6 +5.6 +28.3 +2.1 +104.6 +Total oil equivalent (BOE/d) +29,463 +4,413 +4,697 +363 +38,936 +Average Sales Prices (4) +Oil (per Bbl) +$ +49.08 +$ +50.29 +$ +— +$ +45.52 +$ +49.28 +Natural gas (per Mcf) +$ +4.03 +$ +4.69 +$ +2.83 +$ +2.79 +$ +3.72 +Total oil equivalent (per BOE) +$ +39.41 +$ +45.58 +$ +16.96 +$ +17.69 +$ +37.20 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.80 +$ +10.92 +$ +4.21 +$ +16.77 +$ +6.29 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019 increase d 27% from our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 . This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, as compared to 52,128 BOE per day for the year ended December 31, 2018 . Our average daily oil production for the year ended December 31, 2019 was 38,312 Bbl of oil per day, an increase of 26% from 30,524 Bbl of oil per day for the year ended December 31, 2018 . Our average daily natural gas production for the year ended December 31, 2019 was 167.4 MMcf of natural gas per day, an increase of 29% from 129.6 MMcf of natural gas per day for the year ended December 31, 2018 . +Our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 increased 34% from our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, as compared to 38,936 BOE per day for the year ended December 31, 2017 . Our average daily oil production for the year ended December 31, 2018 was 30,524 Bbl of oil per day, an increase of 42% from 21,510 Bbl of oil per day for the year ended December 31, 2017 . Our average daily natural gas production for the year ended December 31, 2018 was 129.6 MMcf of natural gas per day, an increase of 24% from 104.6 MMcf of natural gas per day for the year ended December 31, 2017 . +17 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2019 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 78% in all wells that we operated at December 31, 2019 . For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +634 +298.6 +123 +55.4 +757 +354.0 +South Texas: +Eagle Ford (2) +139 +117.4 +4 +4.0 +143 +121.4 +Northwest Louisiana: +Haynesville +— +— +246 +20.5 +246 +20.5 +Cotton Valley (3) +1 +1.0 +65 +39.7 +66 +40.7 +Area Total +1 +1.0 +311 +60.2 +312 +61.2 +Total +774 +417.0 +438 +119.6 +1,212 +536.6 +__________________ +(1) +Includes 218 gross (56.5 net) vertical wells that were acquired in multiple transactions. +(2) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2019, 2018 and 2017 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +18 +Table of Contents +At December 31, (1) +2019 +2018 +2017 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +147,991 +123,401 +86,743 +Natural Gas (Bcf) +627.2 +551.5 +396.2 +Total (MBOE) (3) +252,531 +215,313 +152,771 +Estimated proved developed reserves: +Oil (MBbl) +59,667 +53,223 +36,966 +Natural Gas (Bcf) +276.3 +246.2 +190.1 +Total (MBOE) (3) +105,710 +94,261 +68,651 +Percent developed +41.9 +% +43.8 +% +44.9 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +88,324 +70,178 +49,777 +Natural gas (Bcf) +351.0 +305.2 +206.1 +Total (MBOE) (3) +146,821 +121,052 +84,120 +Standardized Measure (4) (in millions) +$ +2,034.0 +$ +2,250.6 +$ +1,258.6 +PV-10 (5) (in millions) +$ +2,248.2 +$ +2,579.3 +$ +1,333.4 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas, for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas and for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2019, 2018 and 2017 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2019, 2018 and 2017 were, in millions, $214.2 , $328.7 and $74.8 , respectively. +Our estimated total proved oil and natural gas reserves increase d 17% from 215.3 million BOE at December 31, 2018 to 252.5 million BOE at December 31, 2019 . We added 58.6 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2019 , approximately 2.4 times our 2019 annual production of 24.2 million BOE. Our proved oil reserves grew 20% from approximately 123.4 million Bbl at December 31, 2018 to approximately 148.0 million Bbl at December 31, 2019 . Our proved natural gas reserves increase d 14% from 551.5 Bcf at December 31, 2018 to 627.2 Bcf at December 31, 2019 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2019 . We realized approximately 5.1 million BOE in net upward revisions to our proved reserves during 2019 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2018 , and despite lower commodity prices used to estimate proved reserves at December 31, 2019 . Our proved reserves to production ratio at December 31, 2019 was 10.5 , a decrease of 7% from 11.3 at December 31, 2018 . +Over the past two years, our estimated total proved oil and natural gas reserves increased 65% from 152.8 million BOE at December 31, 2017 to 252.5 million Bbl at December 31, 2019 . Our proved oil reserves grew 71% from 86.7 million Bbl at December 31, 2017 to 148.0 million Bbl at December 31, 2019 . Our proved developed oil reserves increase d 61% from 37.0 million Bbl at December 31, 2017 to 59.7 million Bbl at December 31, 2019 . +19 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves decrease d 10% from $2.25 billion at December 31, 2018 to $2.03 billion at December 31, 2019 . The PV-10 of our total proved oil and natural gas reserves decrease d 13% from $2.58 billion at December 31, 2018 to $2.25 billion at December 31, 2019 . The decreases in our Standardized Measure and PV-10 are primarily a result of lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2019 , as compared to December 31, 2018 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2019 were $52.19 per Bbl and $2.58 per MMBtu, a decrease of 16% and 17% , respectively, as compared to average oil and natural gas prices of $62.04 per Bbl and $3.10 per MMBtu used to estimate proved reserves at December 31, 2018 . Our total proved reserves were made up of 59% oil and 41% natural gas at December 31, 2019 , as compared to 57% oil and 43% natural gas at December 31, 2018 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +Our proved developed oil and natural gas reserves increase d 12% from 94.3 million BOE at December 31, 2018 to 105.7 million BOE at December 31, 2019 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 12% from 53.2 million Bbl at December 31, 2018 to 59.7 million Bbl at December 31, 2019 . Our proved developed natural gas reserves increase d 12% from 246.2 Bcf at December 31, 2018 to 276.3 Bcf at December 31, 2019 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2019 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2018 +94,261 +Extensions and discoveries +14,206 +Net divestitures of minerals-in-place +(736 +) +Revisions of prior estimates +(1,486 +) +Production +(24,164 +) +Conversion of proved undeveloped to proved developed +23,629 +As of December 31, 2019 +105,710 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d 21% from 121.1 million BOE at December 31, 2018 to 146.8 million BOE at December 31, 2019 . Our proved undeveloped oil and natural gas reserves increased from 70.2 million Bbl and 305.2 Bcf, respectively, at December 31, 2018 to 88.3 million Bbl and 351.0 Bcf, respectively, at December 31, 2019 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2019 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2019 within five years of booking these reserves. +20 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2019 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2018 +121,052 +Extensions and discoveries +44,410 +Net divestitures of minerals-in-place +(1,571 +) +Revisions of prior estimates +6,559 +Conversion of proved undeveloped to proved developed +(23,629 +) +As of December 31, 2019 +146,821 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2016, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2016 +4,705 +13.1 +6,883 +$ +94,579 +2017 +9,300 +45.0 +16,808 +211,860 +2018 +16,009 +61.7 +26,283 +356,830 +2019 +13,832 +58.8 +23,629 +318,609 +Total +43,846 +178.6 +73,603 +$ +981,878 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2019 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +139,595 +559.2 +232,793 +$ +1,877.1 +$ +2,074.8 +South Texas: +Eagle Ford (5) +8,350 +17.2 +11,219 +123.6 +136.6 +Northwest Louisiana +Haynesville +— +45.9 +7,652 +31.0 +34.3 +Cotton Valley (6) +46 +4.9 +867 +2.3 +2.5 +Area Total +46 +50.8 +8,519 +33.3 +36.8 +Total +147,991 +627.2 +252,531 +$ +2,034.0 +$ +2,248.2 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2019 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes +21 +Table of Contents +associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2019 were approximately $ 214.2 million . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Executive Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 42 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2019 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +145,800 +75,000 +85,500 +53,200 +231,300 +128,200 +South Texas: +Eagle Ford +29,200 +26,500 +2,000 +1,900 +31,200 +28,400 +Northwest Louisiana (1) : +Haynesville +17,500 +10,000 +— +— +17,500 +10,000 +Cotton Valley +16,100 +14,900 +— +— +16,100 +14,900 +Area Total (2) +19,700 +18,300 +— +— +19,700 +18,300 +Total +194,700 +119,800 +87,500 +55,100 +282,200 +174,900 +__________________ +(1) +Developed acres include 2,800 gross and net mineral acres in Northwest Louisiana. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +22 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2019 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2025 and beyond totals 12,700 net acres, of which 9,900 net acres do not expire until 2028 and beyond. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2019. +Acres +Acres +Acres +Acres +Acres +Expiring 2020 +Expiring 2021 +Expiring 2022 +Expiring 2023 +Expiring 2024 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +17,000 +10,700 +26,400 +14,800 +18,600 +9,900 +4,800 +4,800 +300 +300 +South Texas: +Eagle Ford +1,600 +1,800 +400 +100 +— +— +— +— +— +— +Total +18,600 +12,500 +26,800 +14,900 +18,600 +9,900 +4,800 +4,800 +300 +300 +__________________ +(1) +Approximately 47% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our 2020 drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2019 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2019, 2018 and 2017 . +Year Ended December 31, +2019 +2018 +2017 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +147 +62.0 +118 +54.7 +72 +43.7 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +25 +13.3 +35 +20.8 +33 +22.3 +Dry +— +— +— +— +— +— +Total Wells +Productive +172 +75.3 +153 +75.5 +105 +66.0 +Dry +— +— +— +— +— +— +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +23 +Table of Contents +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries (“OPEC”), weather conditions, including hurricanes in the Gulf Coast region, oil and natural gas storage levels, transportation capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors — An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +For the years ended December 31, 2019, 2018 and 2017 , we had two, four and four significant purchasers that accounted for approximately 67% , 60% and 60% , respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +24 +Table of Contents +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls +25 +Table of Contents +and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. See “Risk Factors — Approximately 26% of Our Leasehold and Mineral Acres in the Delaware Basin Are Located on Federal Lands, Which Are Subject to Administrative Permitting Requirements and Potential Federal Legislation, Regulation and Orders That May Limit or Restrict Oil and Natural Gas Operations on Federal Lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believed, as of February 25, 2020 , that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System, which is subject to FERC jurisdiction, includes approximately 17 miles of 10-inch diameter crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. We believed, as of February 25, 2020 , that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum +26 +Table of Contents +distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors — We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In January 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would start at $0.60 per MMBtu in 2020 and escalate to $3.00 per MMBtu by 2024. If passed, such a surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors — The Tax Cuts and Jobs Act May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +27 +Table of Contents +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the revision expands the scope of jurisdiction of the CWA, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. However, in June 2017, the EPA and the Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of WOTUS. Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining WOTUS under the CWA that existed prior to the rule. The second step would be a notice-and-comment rule-making in which the agencies would conduct a substantive reevaluation of the definition of WOTUS. In September 2019, the EPA finalized the first step in this process. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the +28 +Table of Contents +environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce, while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For +29 +Table of Contents +example, in October 2014, the Texas Railroad Commission (the “TRC”), adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. For example, certain candidates seeking the office of the President of the United States in 2020 have pledged to ban hydraulic fracturing. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands, which could adversely impact our operations in the Delaware Basin. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In 2019 and 2020, separate bills were introduced in the New Mexico Senate to place a moratorium on hydraulic fracturing. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays” and “Risk Factors — Approximately 26% of Our Leasehold and Mineral Acres in the Delaware Basin Are Located on Federal Lands, Which Are Subject to Administrative Permitting Requirements and Potential Federal Legislation, Regulation and Orders That May Limit or Restrict Oil and Natural Gas Operations on Federal Lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +30 +Table of Contents +We are subject to laws and regulations governing the security of hazardous materials under the Federal Homeland Security Act of 2002, as administered by the Department of Homeland Security (the “DHS”). The DHS promulgated the Chemical Facility Anti-Terrorism Standards to identify and secure chemical facilities that present the greatest security risk using a risk-based tiering structure. Due to the composition of the product it processes, the Black River Processing Plant was required to register with the DHS. We have submitted the required “Top-Screen” survey to the DHS and are awaiting its review by the DHS. We expect to continue to incur costs associated with administrative controls and enhanced physical security measures for the Black River Processing Plant if it is designated as a tiered facility by the DHS. +The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +Approximately 26% of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors — Insurance Against All Operational Risks is Not Available to Us.” +31 +Table of Contents +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 4 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2019 , we had 304 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +Item 1A. Risk Factors. +Risks Related to the Oil and Natural Gas Industry and Our Business +Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. +The prices we receive for the oil and natural gas we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. During 2019 , the average price of oil was $57.01 per Bbl, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the average price of natural gas was $2.53 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2019, oil prices began the year at $45.41 per Bbl, which was the low oil price for 2019, and increased steadily, reaching a high of $66.30 per Bbl in late April . Oil prices declined during the third quarter of 2019 before increasing again during the fourth quarter of 2019 to finish the year at $61.06 per Bbl. In early 2020, oil prices have been particularly volatile, ranging from a high of $65.00 per Bbl in early January to below $45.00 per Bbl in late February. Natural gas prices began 2019 at $2.94 per MMBtu, reached a high of $3.59 per MMBtu in mid-January and declined consistently for several months, reaching a low of $2.07 per MMBtu in early August. Natural gas prices then increased to $2.68 per MMBtu in mid-September before declining again to end 2019 at $2.19 per MMBtu. +Because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. Significant price declines have caused us to recognize full-cost ceiling impairments in the past, and should prices decline significantly again, we may recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules, and These Write-Downs Could Adversely Affect Our Financial Condition.” +32 +Table of Contents +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• +the domestic and foreign supply of, and demand for, oil and natural gas; +• +the actions of OPEC and state-controlled oil companies relating to oil price and production controls; +• +the prices and availability of competitors’ supplies of oil and natural gas; +• +the price and quantity of foreign imports; +• +the impact of U.S. dollar exchange rates; +• +domestic and foreign governmental regulations and taxes; +• +speculative trading of oil and natural gas futures contracts; +• +the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; +• +the availability of refining capacity; +• +the prices and availability of alternative fuel sources; +• +weather conditions and natural disasters; +• +political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America and Russia; +• +domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as the recent coronavirus; +• +the continued threat of terrorism and the impact of military action and civil unrest; +• +public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; +• +the level of global oil and natural gas inventories and exploration and production activity; +• +the impact of energy conservation efforts; +• +technological advances affecting energy consumption; and +• +overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil and natural gas prices do not necessarily fluctuate in direct relation to each other. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +33 +Table of Contents +Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our estimated proved oil and natural gas reserves; +• +the amount of oil and natural gas we produce; +• +the prices at which we sell our production; +• +the costs of developing and producing our oil and natural gas reserves; +• +the costs of constructing, operating and maintaining our midstream facilities; +• +our ability to attract third-party customers for our midstream services; +• +our ability to acquire, locate and produce new reserves; +• +the ability and willingness of banks to lend to us; and +• +our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. +Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or +34 +Table of Contents +abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• +general economic and industry conditions, including the prices received for oil and natural gas; +• +shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• +potential drainage of oil and natural gas from our properties by adjacent operators; +• +the existence or magnitude of faults or unanticipated geological features; +• +loss of or damage to oilfield development and service tools; +• +accidents, equipment failures or mechanical problems; +• +title defects of the underlying properties; +• +increases in severance taxes; +• +adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• +domestic and foreign governmental regulations; and +• +proximity to and capacity of gathering, processing and transportation facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +• +landing our wellbore in the desired drilling zone; +• +staying in the desired drilling zone while drilling horizontally through the formation; +• +running our casing the entire length of the wellbore; +• +fracture stimulating the planned number of stages; +• +drilling out the plugs between stages following hydraulic fracturing operations; and +• +being able to run tools and other equipment consistently through the horizontal wellbore. +Each of these risks is magnified in wells with longer laterals, which we expect to drill more of in 2020, including 74% with completed lateral lengths of two miles. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our Operations Are Subject to Operational Hazards and Risks, Which Could Result in Significant Damages and the Loss of Revenue. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• +natural disasters; +• +adverse weather conditions; +• +domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as the recent coronavirus; +• +loss of drilling fluid circulation; +• +blowouts where oil or natural gas flows uncontrolled at a wellhead; +• +cratering or collapse of the formation; +• +pipe or cement leaks, failures or casing collapses; +• +damage to pipelines, processing plants and disposal wells and associated facilities; +• +fires or explosions; +• +releases of hazardous substances or other waste materials that cause environmental damage; +• +pressures or irregularities in formations; and +• +equipment failures or accidents. +35 +Table of Contents +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Black River Processing Plant owned by San Mateo and operated by us. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected. +Insurance Against All Operational Risks is Not Available to Us. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 87% of our total oil and natural gas production for 2019 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2020 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing facilities and oil, condensate and salt water trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions +36 +Table of Contents +or plant closures for scheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +There Is No Guarantee That We Will Be Successful in Optimizing Our Spacing, Drilling and Completions Techniques in Order to Maximize Our Rate of Return, Cash Flow from Operations and Shareholder Value. +As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. However, due to many factors, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows. +Certain of Our Properties Are in Areas That May Have Been Partially Depleted or Drained by Offset Wells, and Certain of Our Wells May Be Adversely Affected by Actions Other Operators May Take When Drilling, Completing or Operating Wells That They Own. +Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. +Multi-Well Pad Drilling May Result in Volatility in Our Operating Results. +We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become +37 +Table of Contents +challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. +We May Not Be Able to Generate Sufficient Cash to Service All of Our Indebtedness and May Be Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May Not Be Successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We May Incur Additional Indebtedness, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. +As of February 28, 2020, the maximum facility amount under the Credit Agreement was $1.5 billion , the borrowing base was $900.0 million and our elected borrowing commitment was $700.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment. At February 28, 2020, we had available borrowing capacity of approximately $399.0 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that is less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. +As of February 25, 2020 , the facility amount under the San Mateo Credit Facility was $375.0 million , and San Mateo I had available borrowing capacity of approximately $70.8 million (after giving effect to outstanding letters of credit). The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $400.0 million . The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries, but is guaranteed by San Mateo I’s subsidiaries and secured by substantially all of San Mateo I’s assets, including real property. The San Mateo Credit Facility contains covenants restricting San Mateo I’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• +requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• +increasing our vulnerability to general adverse economic and industry conditions; +38 +Table of Contents +• +placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• +restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• +increasing the risk that we may default on our debt obligations. +The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination, and We Are Subject to Interest Rate Risk under Our Credit Agreement and the San Mateo Credit Facility. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 28, 2020, our borrowing base was $900.0 million , our elected borrowing commitment was $700.0 million and we had $255.0 million in outstanding borrowings under, and approximately $46.0 million in outstanding letters of credit issued pursuant to, the Credit Agreement. As of February 28, 2020, the maximum facility amount under the Credit Agreement was $1.5 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment. We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% , and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement), plus 1.0% , plus, in each case, an amount ranging from 0.25% to 1.25% per annum depending on the level of borrowings under the Credit Agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25% to 2.25% per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo I borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 0.50% to 1.50% per annum depending on San Mateo I’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo I borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50% to 2.50% per annum depending on San Mateo I’s Consolidated Total Leverage Ratio. If San Mateo I has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo I’s interest costs, which may have a material adverse effect on San Mateo I’s results of operations and financial condition. +As noted above, under the Credit Agreement and the San Mateo Credit Facility, borrowings in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Each of the Credit Agreement and the San Mateo Credit Facility specify that in the event that LIBOR cannot be determined or other conditions exist with respect to LIBOR, a replacement interest rate that gives due consideration to the then-prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time may be established by the respective administrative agents, in consultation with us. If such an event occurs and we are unable to agree upon a replacement interest rate with our respective administrative agents, we could be unable to make borrowings in the form of Eurodollar loans and would have to borrow funds at the higher base rate, which could increase our cost of capital. Furthermore, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR. An increase in our cost of capital or a disruption in the financial market could have an adverse effect on our business and financial condition. +39 +Table of Contents +The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions. +Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• +incur or guarantee additional debt or issue certain types of preferred stock; +• +pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• +transfer or sell assets; +• +make certain investments; +• +create certain liens; +• +enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• +consolidate, merge or transfer all or substantially all of our assets; +• +engage in transactions with affiliates; and +• +create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. +Similarly, the San Mateo Credit Facility requires San Mateo I to meet a debt to EBITDA ratio, which is defined as consolidated total funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo I to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’s consolidated interest expense, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo I’s EBITDA and interest expense, and therefore San Mateo I’s ability to comply with these covenants. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our Credit Rating May Be Downgraded, Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations. +As of February 25, 2020 , our corporate credit rating from Standard & Poor’s Rating Services was “B+” and our corporate credit rating from Moody’s Investors Service was “B1.” We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +We Depend upon Several Significant Purchasers for the Sale of Most of Our Oil and Natural Gas Production. The Loss of One or More of These Purchasers Could, Among Other Factors, Limit Our Access to Suitable Markets for the Oil and Natural Gas We Produce. +We depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the years ended December 31, 2019 , 2018 and 2017 , we had two , four and four significant purchasers, respectively, that collectively +40 +Table of Contents +accounted for approximately 67% , 60% and 60% , respectively, of our total oil, natural gas and NGL revenues. We cannot assure you that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. +Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third-Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows. +Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +41 +Table of Contents +If Regulatory Changes Prevent Our Ability to Continue to Pool Wells in the Manner We Have Been, It Could Have a Material Adverse Impact on Our Future Production Results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +The Marketability of Our Production Is Dependent upon Oil, Natural Gas and NGL Gathering, Processing and Transportation Facilities, and the Unavailability of Satisfactory Oil, Natural Gas and NGL Gathering, Processing and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas, which would decrease the volumes sold from our wells, and, in certain circumstances, would require us to pay royalties on such flared natural gas. +The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no +42 +Table of Contents +assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering, disposal or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2020 . If we were required to shut in our production or flare our natural gas for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +We Conduct a Portion of Our Operations through Joint Ventures, Which Subjects Us to Additional Risks That Could Have a Material Adverse Effect on the Success of These Operations, Our Financial Position, Results of Operations or Cash Flows. +We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for San Mateo and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows. +Because of the Natural Decline in Production in the Regions of San Mateo’s Midstream Operations, San Mateo’s Long-Term Success Depends on its Ability to Obtain New Sources of Products, Which Depends on Certain Factors Beyond San Mateo’s Control. Any Decrease in Supplies to its Midstream Facilities Could Adversely Affect San Mateo’s Business and Operating Results. +San Mateo’s midstream facilities are or will be connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of third-party activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over third-party producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We Have Entered into Certain Long-Term Contracts That Require Us to Pay Fees to Our Service Providers Based on Minimum Volumes Regardless of Actual Volume Throughput and That May Limit Our Ability to Use Other Service Providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or salt water gathering or transportation agreements, natural gas processing agreements, salt water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2019 , our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $1.2 billion over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +43 +Table of Contents +We Do Not Own All of the Land on Which Our Midstream Assets Are Located, Which Could Disrupt Our Operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Construction of Midstream Projects Subjects Us to Risks of Construction Delays, Cost Over-Runs, Limitations on Our Growth and Negative Effects on Our Financial Condition, Results of Operations, Cash Flows and Liquidity. +From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and water gathering systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of salt water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the judgment of the persons preparing the estimate; and +• +the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, +44 +Table of Contents +appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +actual costs and timing of development and production expenditures; +• +the amount and timing of actual production; and +• +changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles (“GAAP”) is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 58% of Our Total Proved Reserves at December 31, 2019 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. +At December 31, 2019 , approximately 58% of our total proved reserves were undeveloped and less than 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile become increasingly common in the Delaware Basin, we will have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. +At December 31, 2019 , we had leasehold interests in approximately 42,400 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2025 . Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +45 +Table of Contents +The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic and geological data can be expensive to license or obtain, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. +Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, Board of Directors and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +46 +Table of Contents +We Have Limited Control over Activities on Properties We Do Not Operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• +the timing and amount of capital expenditures; +• +the operator’s expertise and financial resources; +• +the rate of production of reserves, if any; +• +approval of other participants in drilling wells; and +• +selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know about or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. +Before acquiring oil and natural gas properties, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be +47 +Table of Contents +able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +Our Ability to Complete Dispositions of Assets, or Interests in Assets, May Be Subject to Factors Beyond Our Control, and in Certain Cases We May Be Required to Retain Liabilities for Certain Matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. +If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the mineral interest owner or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. +It is not our practice in all acquisitions of oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules, and These Write-Downs Could Adversely Affect Our Financial Condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have: +• +downward adjustments to our estimated proved reserves; +• +increases in our estimates of development costs; or +• +deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices +48 +Table of Contents +increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. As of February 25, 2020 , we had approximately 45% of our estimated 2020 oil production hedged in addition to oil basis hedges for approximately 65% of our 2020 Delaware Basin oil production. As of February 25, 2020 , we had no hedges in place for natural gas or NGLs. +An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. +For the first nine months of 2019, most of our natural gas production from the Delaware Basin was sold based upon prices established at the Waha Hub in far West Texas. The price differential between the Waha Hub index and the Henry Hub index reached highs of greater than $4.00 per MMBtu for a brief period at the end of 2018, but narrowed to between $1.00 and $2.00 per MMBtu at the beginning of 2019 and remained there throughout much of the first quarter. The natural gas basis differentials widened significantly in April 2019 for a short period of time, including a few days when natural gas was being sold at Waha for negative prices as high as ($7.00) to ($9.00) per MMBtu on a daily market basis, resulting, in part, from a number of simultaneous outages and maintenance projects impacting major pipelines in the area. In response to these basis differentials, we temporarily shut in certain high gas-oil ratio wells to mitigate the impact of these negative prices on our results. Despite improving during the second half of 2019, beginning in the fourth quarter, the Waha basis differentials widened further at times, and natural gas prices at the Waha hub were slightly negative on certain days in late December 2019. In early 2020, the outlook for the Waha basis differentials has deteriorated further. +Similarly, much of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas. The price differential between the West Texas Intermediate oil price and the oil price at the Midland Hub, also known as the Midland-Cushing (Oklahoma) differential, was approximately $5.00 per Bbl at the beginning of 2019. This oil price differential narrowed to less than $1.00 per Bbl during the first quarter of 2019 but widened again during the second quarter to levels +49 +Table of Contents +experienced at the beginning of the year. The Midland-Cushing (Oklahoma) oil price differential narrowed again in the third quarter of 2019, became positive late in the third quarter and remained positive throughout the fourth quarter of 2019, although it is possible that the differential could become negative again at certain times during 2020. We have limited oil basis hedges in place to mitigate our exposure to these oil price differentials during 2020, 2021 and 2022, and we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials. +These widening oil and natural gas basis differentials are largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +We anticipate that the volatility in these oil and natural gas price differentials could persist throughout 2020 or longer until additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is completed. We can provide no assurances as to how long these volatile differentials may persist, and as noted above, these price differentials could widen further in future periods. Should we experience future periods of negative pricing for natural gas as we did during the second quarter of 2019, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. +Approximately 26% of Our Leasehold and Mineral Acres in the Delaware Basin Are Located on Federal Lands, Which Are Subject to Administrative Permitting Requirements and Potential Federal Legislation, Regulation and Orders That May Limit or Restrict Oil and Natural Gas Operations on Federal Lands. +At December 31, 2019, Matador held approximately 128,200 net leasehold and mineral acres in the Delaware Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 33,000 net acres, or about 26%, were on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. Certain candidates seeking the office of the President of the United States in 2020 have proposed a ban of new leases for production of minerals on federal properties, which would also limit our ability to acquire additional federal leasehold. At the federal level, various policy makers, regulatory agencies and political candidates, including presidential candidates, have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results +50 +Table of Contents +of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments for: +• +personal injuries; +• +property damage; +• +containment and clean-up of oil, produced water and other spills; +• +management and disposal of hazardous materials; +• +remediation, clean-up costs and natural resource damages; and +• +other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Furthermore, we participate in candidate conservation agreements for the lesser prairie-chicken, the sand dune lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. Participation in such agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have an adverse impact on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” +We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The Tax Cuts and Jobs Act did not include any of these proposals, except for the repeal of the domestic manufacturing tax deduction for oil and natural gas companies. However, it is possible that such provisions could be proposed in the future. The passage of any legislation or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +51 +Table of Contents +In January 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would start at $0.60 per MMBtu in 2020 and escalate to $3.00 per MMBtu by 2024. Although the bill was not passed in 2019, any such surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. +The Tax Cuts and Jobs Act May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods. +The Tax Cuts and Jobs Act includes provisions that generally (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our business interest income) for the year, (ii) permit us to offset only 80% (rather than 100%) of our taxable income with net operating losses we generate and (iii) limit our ability to deduct certain elements of executive compensation. Interest expense and net operating losses subject to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the Tax Cuts and Jobs Act repealed the domestic manufacturing tax deduction for oil and natural gas companies. These tax law changes could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might not have incurred otherwise, in the absence of these tax law changes. +Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands. These rules were rescinded by rule in December 2017; however, in January 2018, California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the rules. This litigation is ongoing and future implementation of the BLM rules is uncertain at this time. +Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. For example, certain candidates seeking the office of the President of the United States in 2020 have pledged to ban hydraulic fracturing. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands, which could adversely impact our operations in the Delaware Basin. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. In 2019 and 2020, separate bills were introduced in the New Mexico Senate to place a moratorium on hydraulic fracturing. Although such bills have not passed, similar laws, rules, regulations or orders at the local, state or federal level could limit our operations. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The Potential Adoption of Federal, State and Local Legislation and Regulations Intended to Address Potential Induced Seismicity in the Areas in Which We Operate Could Restrict Our Drilling and Production Activities, as well as Our Ability to Dispose of Produced Water Gathered from Such Activities, Which Could Decrease San Mateo’s Revenues and Result in Increased Costs and Additional Operating Restrictions or Delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such +52 +Table of Contents +events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could decrease San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce, while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. In November 2019, the Trump administration formally moved to exit the Paris Agreement, initiating the treaty-mandated one-year process at the end of which the United States can officially exit the agreement. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and natural gas industry. However, in June 2017, the EPA proposed a two-year stay of certain requirements under this rule and in August 2019 proposed to eliminate the methane emissions limitations under the rule. Any future international agreements, federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs, adversely affecting our profits, and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to +53 +Table of Contents +Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels, including candidates seeking the office of the President of the United States in 2020, have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. Any such restrictions or prohibitions, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes. +New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or our customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. The BLM then finalized a revised rule in 2018 that scaled back the waste-prevention requirements of the 2016 rule. Environmental groups as well as California and New Mexico have sued in federal district court to challenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. If not withdrawn or significantly revised, these rules are expected to result in an increase to our operating costs and changes in our operations. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations. +We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. +54 +Table of Contents +PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the TRC and the New Mexico Oil Conservation Division could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by FERC May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. In December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System, which is subject to FERC jurisdiction and includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The Rates of Our Regulated Assets are Subject to Review and Reporting by Federal Regulators, Which Could Adversely Affect Our Revenues. +The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.2 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +55 +Table of Contents +The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or +56 +Table of Contents +become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or Financial Loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our supervisory control and data acquisition (SCADA) systems, control important processes and facilities that are critical to our operations. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. +While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +We Operate in a Litigious Environment and May Be Involved in Legal Proceedings That Could Have an Adverse Effect on Our Results of Operations and Financial Condition. +Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Risks Relating to Our Common Stock +The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2019 , our stock price fluctuated between a high of $22.25 and a low of $12.16 . In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• +our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• +quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• +changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• +speculation in the press or investment community; +57 +Table of Contents +• +announcement or consummation of acquisitions, dispositions or joint ventures by us; +• +public reaction to our operations or plans, press releases, announcements and filings with the SEC; +• +the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; +• +sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• +general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• +domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as the recent coronavirus; +• +the realization of any of the risk factors presented in this Annual Report; +• +the recruitment or departure of key personnel; +• +commencement of, involvement in or unfavorable resolution of litigation; +• +the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• +changes in market valuations of companies similar to ours; and +• +domestic and international economic, legal and regulatory factors unrelated to our performance. +Conservation Measures and a Negative Shift in Market Perception towards the Oil and Natural Gas Industry Could Adversely Affect Demand for Oil and Natural Gas and Our Stock Price. +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. +Certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale play arena. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected. +If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +58 +Table of Contents +We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. +We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. +Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• +authorization for our Board of Directors to issue preferred stock without shareholder approval; +• +a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• +the prohibition of cumulative voting in the election of directors; and +• +a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +Our Directors and Executive Officers Own a Significant Percentage of Our Equity, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. +As of February 28, 2020 , our directors and executive officers beneficially owned approximately 7% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +59 +Table of Contents +Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows. +On November 4, 2019, the Company received a Notice of Violation and Finding of Violation from the EPA and a Notice of Violation from the New Mexico Environment Department (the “NMED”) alleging violations of the CAA and New Mexico State Implementation Plan at certain of its operated locations in New Mexico. The Company has provided information to the EPA and NMED and is engaged in discussions regarding a resolution of the alleged violations. The Company believes it is remote that the resolution of this matter will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. Resolution of the matter may result in monetary sanctions of more than $100,000. +Item 4. Mine Safety Disclosures. +Not applicable. +60 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 28, 2020 , we had 116,569,389 shares of common stock outstanding held by approximately 360 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2019 . +Equity Compensation Plan Information +Plan Category +Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights +Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights +Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1) (2) +3,956,574 +$ +22.64 +2,801,761 +Equity compensation plans not approved by security holders +— +— +— +Total +3,956,574 +$ +22.64 +2,801,761 +__________________ +(1) +Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan (the “2003 Plan”) or the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). +(2) +The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board of Directors in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report. +61 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2014 through December 31, 2019 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +62 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2019 , the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs +Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2019 to October 31, 2019 +163 +$ +13.65 +— +— +November 1, 2019 to November 30, 2019 +784 +14.18 +— +— +December 1, 2019 to December 31, 2019 +— +— +— +— +Total +947 +$ +14.09 +— +— +_________________ +(1) +The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +63 +Table of Contents +Item 6. Selected Financial Data. +The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2019 and selected consolidated balance sheet and cash flow data at December 31, 2019 , 2018 , 2017 , 2016 and 2015 . You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto included elsewhere in this Annual Report. The financial information included in this Annual Report may not be indicative of our future results of operations, financial condition or cash flows. +Year Ended December 31, +2019 +2018 +2017 +2016 +2015 +(In thousands, except per share data) +Statement of operations data: +Revenues +Oil and natural gas revenues +$ +892,325 +$ +800,700 +$ +528,684 +$ +291,156 +$ +278,340 +Third-party midstream services revenues +59,110 +21,920 +10,198 +5,218 +1,864 +Sales of purchased natural gas +74,769 +7,071 +— +— +— +Lease bonus - mineral acreage +1,711 +2,489 +— +— +— +Realized gain (loss) on derivatives +9,482 +2,334 +(4,321 +) +9,286 +77,094 +Unrealized (loss) gain on derivatives +(53,727 +) +65,085 +9,715 +(41,238 +) +(39,265 +) +Total revenues +983,670 +899,599 +544,276 +264,422 +318,033 +Expenses +Production taxes, transportation and processing +92,273 +76,138 +58,275 +43,046 +35,650 +Lease operating +117,305 +92,966 +67,313 +56,202 +54,704 +Plant and other midstream services operating +36,798 +24,609 +13,039 +5,389 +3,489 +Purchased natural gas +69,398 +6,635 +— +— +— +Depletion, depreciation and amortization +350,540 +265,142 +177,502 +122,048 +178,847 +Accretion of asset retirement obligations +1,822 +1,530 +1,290 +1,182 +734 +Full-cost ceiling impairment +— +— +— +158,633 +801,166 +General and administrative +80,054 +69,308 +66,016 +55,089 +50,105 +Total expenses +748,190 +536,328 +383,435 +441,589 +1,124,695 +Operating income (loss) +235,480 +363,271 +160,841 +(177,167 +) +(806,662 +) +Other income (expense) +Net (loss) gain on asset sales and inventory impairment +(967 +) +(196 +) +23 +107,277 +908 +Interest expense +(73,873 +) +(41,327 +) +(34,565 +) +(28,199 +) +(21,754 +) +Prepayment premium on extinguishment of debt +— +(31,226 +) +— +— +— +Other (expense) income +(2,126 +) +1,551 +3,551 +(4 +) +616 +Total other (expense) income +(76,966 +) +(71,198 +) +(30,991 +) +79,074 +(20,230 +) +Income (loss) before income taxes +158,514 +292,073 +129,850 +(98,093 +) +(826,892 +) +Income tax provision (benefit) +Current +— +(455 +) +(8,157 +) +(1,036 +) +2,959 +Deferred +35,532 +(7,236 +) +— +— +(150,327 +) +Total income tax provision (benefit) +35,532 +(7,691 +) +(8,157 +) +(1,036 +) +(147,368 +) +Net income (loss) +122,982 +299,764 +138,007 +(97,057 +) +(679,524 +) +Net income attributable to non-controlling interest in subsidiaries +(35,205 +) +(25,557 +) +(12,140 +) +(364 +) +(261 +) +Net income (loss) attributable to Matador Resources Company shareholders +$ +87,777 +$ +274,207 +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +Earnings (loss) per common share +Basic +$ +0.75 +$ +2.41 +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +Diluted +$ +0.75 +$ +2.41 +$ +1.23 +$ +(1.07 +) +$ +(8.34 +) +64 +Table of Contents +At December 31, +2019 +2018 +2017 +2016 +2015 +(In thousands) +Balance sheet data: +Cash and cash equivalents +$ +40,024 +$ +64,545 +$ +96,505 +$ +212,884 +$ +16,732 +Restricted cash +$ +25,104 +$ +19,439 +$ +5,977 +$ +1,258 +$ +44,357 +Net property and equipment +$ +3,699,595 +$ +3,122,864 +$ +1,881,456 +$ +1,184,525 +$ +1,012,406 +Total assets +$ +4,069,676 +$ +3,455,518 +$ +2,145,690 +$ +1,464,665 +$ +1,140,861 +Current liabilities +$ +399,772 +$ +330,022 +$ +282,606 +$ +169,505 +$ +136,830 +Long-term liabilities +$ +1,700,452 +$ +1,345,839 +$ +605,538 +$ +603,715 +$ +515,072 +Total Matador Resources Company shareholders’ equity +$ +1,833,654 +$ +1,688,880 +$ +1,156,556 +$ +690,125 +$ +488,003 +Year Ended December 31, +2019 +2018 +2017 +2016 +2015 +(In thousands) +Other financial data: +Net cash provided by operating activities +$ +552,042 +$ +608,523 +$ +299,125 +$ +134,086 +$ +208,535 +Net cash used in investing activities +$ +(903,976 +) +$ +(1,515,253 +) +$ +(819,284 +) +$ +(448,739 +) +$ +(381,406 +) +Oil and natural gas properties capital expenditures +$ +(730,161 +) +$ +(1,357,802 +) +$ +(699,445 +) +$ +(379,067 +) +$ +(432,715 +) +Midstream capital expenditures +$ +(192,035 +) +$ +(163,222 +) +$ +(115,128 +) +$ +(74,845 +) +$ +(64,499 +) +Net cash provided by financing activities +$ +333,078 +$ +888,232 +$ +408,499 +$ +467,706 +$ +224,944 +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ +610,756 +$ +553,223 +$ +336,063 +$ +157,892 +$ +223,138 +__________________ +(1) +Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. +Non-GAAP Financial Measures +We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, prepayment premium on extinguishment of debt and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +65 +Table of Contents +The following table presents our calculation of Adjusted EBITDA, on a consolidated basis, and the reconciliation of such Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2019 +2018 +2017 +2016 +2015 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net income (loss) attributable to Matador Resources Company shareholders +$ +87,777 +$ +274,207 +$ +125,867 +$ +(97,421 +) +$ +(679,785 +) +Net income attributable to non-controlling interest in subsidiaries +35,205 +25,557 +12,140 +364 +261 +Net income (loss) +122,982 +299,764 +138,007 +(97,057 +) +(679,524 +) +Interest expense +73,873 +41,327 +34,565 +28,199 +21,754 +Total income tax provision (benefit) +35,532 +(7,691 +) +(8,157 +) +(1,036 +) +(147,368 +) +Depletion, depreciation and amortization +350,540 +265,142 +177,502 +122,048 +178,847 +Accretion of asset retirement obligations +1,822 +1,530 +1,290 +1,182 +734 +Full-cost ceiling impairment +— +— +— +158,633 +801,166 +Unrealized loss (gain) on derivatives +53,727 +(65,085 +) +(9,715 +) +41,238 +39,265 +Stock-based compensation expense +18,505 +17,200 +16,654 +12,362 +9,450 +Net loss (gain) on asset sales and inventory impairment +967 +196 +(23 +) +(107,277 +) +(908 +) +Prepayment premium on extinguishment of debt +— +31,226 +— +— +— +Consolidated Adjusted EBITDA +657,948 +583,609 +350,123 +158,292 +223,416 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries +(47,192 +) +(30,386 +) +(14,060 +) +(400 +) +(278 +) +Adjusted EBITDA attributable to Matador Resources Company shareholders +$ +610,756 +$ +553,223 +$ +336,063 +$ +157,892 +$ +223,138 +Year Ended December 31, +2019 +2018 +2017 +2016 +2015 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities +$ +552,042 +$ +608,523 +$ +299,125 +$ +134,086 +$ +208,535 +Net change in operating assets and liabilities +34,517 +(64,429 +) +25,058 +(1,809 +) +(8,980 +) +Interest expense, net of non-cash portion +71,389 +39,970 +34,097 +27,051 +20,902 +Current income tax (benefit) provision +— +(455 +) +(8,157 +) +(1,036 +) +2,959 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries +(47,192 +) +(30,386 +) +(14,060 +) +(400 +) +(278 +) +Adjusted EBITDA attributable to Matador Resources Company shareholders +610,756 +553,223 +336,063 +157,892 +223,138 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +For a comparison of our results of operations for the years ended December 31, 2018 and December 31, 2017, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 1, 2019. +Overview +We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other +66 +Table of Contents +unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +2019 Operational Highlights +During the year ended December 31, 2019 , we completed and began producing oil and natural gas from 76 gross (61.4 net) operated and 62 gross (4.3 net) non-operated wells in the Delaware Basin and from eight gross (7.9 net) operated wells in South Texas. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019 , although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that began producing in 2019 . +During 2019 , we continued our focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We operated six drilling rigs in the Delaware Basin throughout 2019 . In October 2018, we commenced a drilling program in South Texas to drill nine wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and hold by production almost all of our remaining undeveloped acreage in South Texas. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight wells, including one well drilled in the Austin Chalk formation, were completed and turned to sales in the first half of 2019. +The vast majority of our 2019 capital expenditures was directed to (i) the delineation and development of our leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin and (iv) the acquisition of additional leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to our short-term drilling and completion program in South Texas and to our participation in several non-operated wells drilled and completed in the Haynesville shale throughout 2019. +Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, an increase of 27% , as compared to 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, for the year ended December 31, 2018 . Our average daily oil production in 2019 of 38,312 Bbl of oil per day increase d 26% from 30,524 Bbl of oil per day in 2018 . This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin as well as from our nine-well program in South Texas concluded in the first half of 2019. Our average daily natural gas production of 167.4 MMcf per day in 2019 increase d 29% from 129.6 MMcf per day in 2018. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin as well as from non-operated Haynesville shale wells completed and turned to sales during the third quarter of 2019. Oil production comprised 58% of our total production for the year ended December 31, 2019 , as compared to 59% for the year ended December 31, 2018 . +For the year ended December 31, 2019 , our oil and natural gas revenues were $892.3 million , an increase of 11% from oil and natural gas revenues of $800.7 million for the year ended December 31, 2018 . Our oil revenues increased 20% to approximately $759.8 million , as compared to $635.6 million for the year ended December 31, 2018 . The increase in oil revenues resulted from the increase in oil production for the year ended December 31, 2019 noted above, partially offset by a lower weighted average realized oil price of $54.34 per Bbl in 2019 , as compared to $57.04 per Bbl in 2018 . Our natural gas revenues decreased 20% to approximately $132.5 million , as compared to $165.1 million for the year ended December 31, 2018 . The decrease in natural gas revenues resulted from a lower weighted average realized natural gas price of $2.17 per Mcf in 2019 , as compared to $3.49 per Mcf in 2018 . This decrease was partially offset by the increase in our natural gas production noted above. +We reported net income attributable to Matador shareholders of approximately $87.8 million , or $0.75 per diluted common share, on a GAAP basis for the year ended December 31, 2019 , as compared to net income of $274.2 million , or $2.41 per diluted common share, for the year ended December 31, 2018 . Adjusted EBITDA for the year ended December 31, 2019 was $610.8 million , as compared to Adjusted EBITDA of $553.2 million for the year ended December 31, 2018 . Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” +At December 31, 2019 , our estimated total proved oil and natural gas reserves were 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, with a Standardized Measure of $2.03 billion and a PV-10 of $2.25 billion . At +67 +Table of Contents +December 31, 2018 , our estimated total proved oil and natural gas reserves were 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, with a Standardized Measure of $2.25 billion and a PV-10 of $2.58 billion . Our estimated total proved reserves of 252.5 million BOE at December 31, 2019 represented a 17% year-over-year increase , as compared to 215.3 million BOE at December 31, 2018 . Our estimated proved oil reserves of 148.0 million Bbl at December 31, 2019 increase d 20% , as compared to 123.4 million Bbl at December 31, 2018 . Our proved oil and natural gas reserves in the Delaware Basin increase d 22% to 232.8 million BOE at December 31, 2019 , as compared to 191.5 million BOE at December 31, 2018 , primarily as a result of our ongoing delineation and development operations there. At December 31, 2019 , approximately 92% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increase d 22% to 139.6 million Bbl at December 31, 2019 , as compared to 114.8 million Bbl at December 31, 2018 . Proved oil reserves comprised 59% of our total proved reserves at December 31, 2019 , as compared to 57% at December 31, 2018 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” +Midstream Highlights +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. As part of this transaction, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. In addition, Five Point has committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. Five Point has also provided us the opportunity to earn deferred performance incentives of up to $150.0 million over the next several years as we execute our operational plans in and around the Greater Stebbins Area and the Stateline asset area, plus additional performance incentives for securing volumes from third-party customers. +San Mateo achieved strong operating results in 2019, highlighted by (i) increased third-party midstream services revenues, (ii) increased natural gas gathering and processing volumes, (iii) increased water gathering and water disposal volumes and (iv) increased oil gathering volumes, all as compared to 2018. San Mateo initiated construction on an additional 200 MMcf per day of designed natural gas processing inlet capacity as part of the expansion of the Black River Processing Plant, which is anticipated to be placed in service during the summer of 2020 and would bring the total designed inlet capacity of the Black River Processing Plant to 460 MMcf of natural gas per day. San Mateo also initiated plans to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. During 2019, San Mateo added four commercial salt water disposal wells, two in the Rustler Breaks asset area and two in the Greater Stebbins Area, and expects to place into service one additional commercial salt water disposal well in the Rustler Breaks asset area late in the first quarter of 2020, bringing San Mateo’s designed salt water disposal capacity to approximately 335,000 Bbl per day. +During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes, obtained significant additional acreage dedications from existing salt water customers and added an acreage dedication from a new oil customer. At certain times near the end of the third quarter and in the fourth quarter of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day. +68 +Table of Contents +2020 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2020 . We plan to operate six contracted drilling rigs drilling primarily oil and natural gas wells in the Delaware Basin throughout 2020 . Our 2020 estimated capital expenditure budget consists of $690.0 to $750.0 million for drilling, completing and equipping wells (“D/C/E capital expenditures”) and $85.0 to $105.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated combined 2020 capital expenditures of $190.0 to $235.0 million and also accounts for the remaining portions of the $50.0 million capital carry that Five Point agreed to provide to us in conjunction with the formation of San Mateo II. Substantially all of these 2020 estimated capital expenditures will be allocated to (i) the further delineation and development of our leasehold position, (ii) the continued construction of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2020 Delaware Basin drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a particular emphasis on drilling and completing a higher percentage of longer horizontal wells in 2020, including 74% with anticipated completed lateral lengths of two miles. +To narrow any potential difference between our 2020 capital expenditures and operating cash flows, we may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position (as we did in 2019), as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during 2020 . These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2020 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2020 . +At December 31, 2019 , we had $40.0 million in cash (excluding restricted cash) and $198.9 million in undrawn borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $500.0 million ). The Credit Agreement was amended in February 2020 to increase our elected borrowing commitment from $500.0 million to $700.0 million, which increased our undrawn borrowing capacity to $399.0 million (after giving effect to then-outstanding letters of credit). Excluding any possible significant acquisitions, we expect to fund our 2020 capital expenditures through a combination of cash on hand, operating cash flows, performance incentives in connection with San Mateo, borrowings under our Credit Agreement (assuming availability under our borrowing base of $900.0 million ) and borrowings under the San Mateo Credit Facility (assuming availability under the accordion feature of such facility to up to $400.0 million). In addition, in 2020, we expect to receive a portion of the $50.0 million capital carry Five Point agreed to provide to us in conjunction with the formation of San Mateo II. We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. The aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. +69 +Table of Contents +Revenues +Our revenues are derived primarily from the sale of oil, natural gas and NGL production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or NGL prices. +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2019 +2018 +2017 +Operating Data: +Revenues (in thousands): (1) +Oil +$ +759,811 +$ +635,554 +$ +386,865 +Natural gas +132,514 +165,146 +141,819 +Total oil and natural gas revenues +892,325 +800,700 +528,684 +Third-party midstream services revenues +59,110 +21,920 +10,198 +Sales of purchased natural gas +74,769 +7,071 +— +Lease bonus - mineral acreage +1,711 +2,489 +— +Realized gain (loss) on derivatives +9,482 +2,334 +(4,321 +) +Unrealized (loss) gain on derivatives +(53,727 +) +65,085 +9,715 +Total revenues +$ +983,670 +$ +899,599 +$ +544,276 +Net Production Volumes: (1) +Oil (MBbl) +13,984 +11,141 +7,851 +Natural gas (Bcf) +61.1 +47.3 +38.2 +Total oil equivalent (MBOE) (2) +24,164 +19,026 +14,212 +Average daily production (BOE/d) (2) +66,203 +52,128 +38,936 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +54.34 +$ +57.04 +$ +49.28 +Oil, with realized derivatives (per Bbl) +$ +54.98 +$ +57.38 +$ +48.81 +Natural gas, without realized derivatives (per Mcf) +$ +2.17 +$ +3.49 +$ +3.72 +Natural gas, with realized derivatives (per Mcf) +$ +2.18 +$ +3.46 +$ +3.70 +________________ +(1) +We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2019 as Compared to Year Ended December 31, 2018 +Oil and natural gas revenues . Our oil and natural gas revenues increase d $91.6 million , or 11% , to $892.3 million for the year ended December 31, 2019 , as compared to $800.7 million for the year ended December 31, 2018 . Our oil revenues increase d $124.3 million , or 20% , to $759.8 million for the year ended December 31, 2019 , as compared to $635.6 million for the year ended December 31, 2018 . This increase in our oil revenues resulted primarily from the 26% increase in our oil production to 14.0 million Bbl of oil for the year ended December 31, 2019 , as compared to 11.1 million Bbl of oil for the year ended December 31, 2018 . The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, as well as our nine-well program in the Eagle Ford shale play concluded in the first half of 2019. This increase was partially offset by a 5% decrease in the weighted average oil price realized for the year ended December 31, 2019 to $54.34 per Bbl, as compared to $57.04 per Bbl realized for the year ended December 31, 2018 . Our natural gas revenues decrease d by $32.6 million , or 20% , to $132.5 million for the year ended December 31, 2019 , as compared to $165.1 million for the year ended December 31, 2018 . The decrease in natural gas revenues resulted primarily from a 38% decrease in realized natural gas prices to $2.17 per Mcf for the year ended December 31, 2019 , as compared to $3.49 per Mcf realized for the year ended December 31, 2018 . This decrease was partially offset by the 29% increase in our natural gas production to 61.1 Bcf for the year ended December 31, 2019 , as compared to 47.3 Bcf for the year ended December 31, 2018 . The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin as well as from non-operated Haynesville shale wells completed and turned to sales during the year ended December 31, 2019 . +Third-party midstream services revenues. Our third-party midstream services revenues increase d $37.2 million , or 170% , to $59.1 million for the year ended December 31, 2019 , as compared to $21.9 million for the year ended December 31, 2018 . Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party +70 +Table of Contents +natural gas gathering, transportation and processing revenues to approximately $27.0 million for the year ended December 31, 2019 , as compared to $10.7 million for the year ended December 31, 2018 , (ii) an increase in third-party salt water gathering and disposal revenues to approximately $24.9 million for the year ended December 31, 2019 , as compared to approximately $10.5 million for the year ended December 31, 2018 , and (iii) an increase in our third-party oil transportation revenues to approximately $7.2 million for the year ended December 31, 2019 , as compared to $0.7 million for the year ended December 31, 2018 . +Sales of purchased natural gas. Our sales of purchased natural gas were $74.8 million for the year ended December 31, 2019 , as compared to $7.1 million for the year ended December 31, 2018 . Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas, process the natural gas at the Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statement of operations. +Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $1.7 million for the year ended December 31, 2019 , as compared to $2.5 million for the year ended December 31, 2018 . Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests. +Realized gain on derivatives . Our realized net gain on derivatives was $9.5 million for the year ended December 31, 2019 , as compared to a realized net gain of approximately $2.3 million for the year ended December 31, 2018 . We realized a net gain of $8.9 million and $0.5 million from our oil and natural gas costless collar contracts, respectively, for the year ended December 31, 2019 , resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. We realized a net gain of $0.1 million from our oil basis swap contracts for the year ended December 31, 2019 , resulting from oil basis prices that were lower than the swap prices on certain of our oil basis swap contracts. We realized a net gain of $29.5 million from our oil basis swap contracts for the year ended December 31, 2018, resulting from oil basis prices that were lower than the swap prices on certain of our oil basis swap contracts. This net gain was significantly offset by net losses of $25.7 million and $1.4 million from our oil and natural gas costless collar contracts, respectively, for the year ended December 31, 2018, resulting from oil and natural gas prices that were above the short call/ceiling prices of certain of our oil and natural gas costless collar contracts. We realized an average gain on our oil derivatives of approximately $0.64 per Bbl of oil produced during the year ended December 31, 2019 , as compared to an average gain of $0.34 per Bbl of oil produced during the year ended December 31, 2018 . Our total oil volumes hedged for the year ended December 31, 2019 represented 59% of our total oil production, as compared to 49% of our total oil production for the year ended December 31, 2018 . We realized an average gain on our natural gas derivatives of approximately $0.01 per Mcf produced during the year ended December 31, 2019 , as compared to an average loss of approximately $0.03 per Mcf produced for the year ended December 31, 2018 . Our total natural gas volumes hedged for the year ended December 31, 2019 represented 12% of our total natural gas production, as compared to 36% of our total natural gas production for the year ended December 31, 2018 . +Unrealized (loss) gain on derivatives. Our unrealized loss on derivatives was approximately $53.7 million for the year ended December 31, 2019 , as compared to an unrealized gain of $65.1 million for the year ended December 31, 2018 . During the year ended December 31, 2019 , the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts decrease d from a net asset of approximately $49.8 million to a net liability of approximately $3.9 million , resulting in an unrealized loss on derivatives of approximately $53.7 million for the year ended December 31, 2019 . During the year ended December 31, 2018 , the aggregate net fair value of our open oil and natural gas derivative contracts increased from a net liability of approximately $15.2 million to a net asset of approximately $49.8 million , resulting in an unrealized gain on derivatives of approximately $65.1 million for the year ended December 31, 2018 . +71 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2019 +2018 +2017 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing +$ +92,273 +$ +76,138 +$ +58,275 +Lease operating +117,305 +92,966 +67,313 +Plant and other midstream services operating +36,798 +24,609 +13,039 +Purchased natural gas +69,398 +6,635 +— +Depletion, depreciation and amortization +350,540 +265,142 +177,502 +Accretion of asset retirement obligations +1,822 +1,530 +1,290 +General and administrative +80,054 +69,308 +66,016 +Total expenses +748,190 +536,328 +383,435 +Operating income +235,480 +363,271 +160,841 +Other income (expense): +Net (loss) gain on asset sales and inventory impairment +(967 +) +(196 +) +23 +Interest expense +(73,873 +) +(41,327 +) +(34,565 +) +Prepayment premium on extinguishment of debt +— +(31,226 +) +— +Other (expense) income +(2,126 +) +1,551 +3,551 +Total other (expense) income +(76,966 +) +(71,198 +) +(30,991 +) +Income before income taxes +158,514 +292,073 +129,850 +Total income tax provision (benefit) +35,532 +(7,691 +) +(8,157 +) +Net income attributable to non-controlling interest in subsidiaries +(35,205 +) +(25,557 +) +(12,140 +) +Net income attributable to Matador Resources Company shareholders +$ +87,777 +$ +274,207 +$ +125,867 +Expenses per BOE: +Production taxes, transportation and processing +$ +3.82 +$ +4.00 +$ +4.10 +Lease operating +$ +4.85 +$ +4.89 +$ +4.74 +Plant and other midstream services operating +$ +1.52 +$ +1.29 +$ +0.92 +Depletion, depreciation and amortization +$ +14.51 +$ +13.94 +$ +12.49 +General and administrative +$ +3.31 +$ +3.64 +$ +4.65 +Year Ended December 31, 2019 as Compared to Year Ended December 31, 2018 +Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increase d $16.1 million , or 21% , to $92.3 million for the year ended December 31, 2019 , as compared to $76.1 million for the year ended December 31, 2018 . This increase was primarily attributable to the $5.3 million increase in our production taxes to $63.3 million for the year ended December 31, 2019 , as compared to $58.0 million for the year ended December 31, 2018 , resulting from the $91.6 million increase in oil and natural gas revenues for the year ended December 31, 2019 , as compared to the year ended December 31, 2018 . Transportation and processing expenses increased to $29.0 million for the year ended December 31, 2019 , as compared to $18.2 million for the year ended December 31, 2018 , primarily resulting from the 27% increase in total oil equivalent production between the respective periods. On a unit-of-production basis, our production taxes and transportation and processing expenses decrease d to $3.82 per BOE for the year ended December 31, 2019 , as compared to $4.00 per BOE for the year ended December 31, 2018 , as the 27% increase in total oil equivalent production between the respective periods more than offset the 21% increase in our production taxes, transportation and processing expenses. +Lease operating expenses. Our lease operating expenses increase d $24.3 million , or 26% , to $117.3 million for the year ended December 31, 2019 , as compared to $93.0 million for the year ended December 31, 2018 . The increase in lease operating expenses for the year ended December 31, 2019 was primarily attributable to an increase in the costs of services and equipment related to the increased number of wells we operated during the year ended December 31, 2019 . Our lease operating expenses on a unit-of-production basis decrease d 1% to $4.85 per BOE for the year ended December 31, 2019 , as compared to $4.89 per BOE for the year ended December 31, 2018 , as the 26% increase in total lease operating expenses was approximately offset by the 27% increase in total equivalent oil production between the respective periods. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increase d $12.2 million , or 50% , to $36.8 million for the year ended December 31, 2019 , as compared to $24.6 million for the year ended December 31, 2018 . This increase was primarily attributable to (i) increased expenses associated with our expanded commercial salt water disposal operations of $18.1 million for the year ended December 31, 2019 , as compared to $13.1 +72 +Table of Contents +million for the year ended December 31, 2018 , (ii) increased expenses associated with the Black River Processing Plant, which was expanded late in the first quarter of 2018, of $11.0 million for the year ended December 31, 2019 , as compared to $7.6 million for the year ended December 31, 2018 , and (iii) increased expenses associated with pipeline operations of $7.9 million for the year ended December 31, 2019 , as compared to $3.5 million for the year ended December 31, 2018 . +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increase d $85.4 million , or 32% , to $350.5 million for the year ended December 31, 2019 , as compared to $265.1 million for the year ended December 31, 2018 . On a unit-of-production basis, our depletion, depreciation and amortization expenses increase d 4% to $14.51 per BOE for the year ended December 31, 2019 , as compared to $13.94 per BOE for the year ended December 31, 2018 . These increase s were primarily attributable to (i) a somewhat higher depletion rate in 2019 as compared to 2018, resulting from our total equivalent oil production growth being slightly greater than the growth in our total proved oil and natural gas reserves, and (ii) increased depreciation expenses associated with our expanded midstream assets of approximately $16.1 million for the year ended December 31, 2019 , as compared to $10.5 million for the year ended December 31, 2018 . +General and administrative. Our general and administrative expenses increase d $10.7 million , or 16% , to $80.1 million for the year ended December 31, 2019 , as compared to $69.3 million for the year ended December 31, 2018 . The increase in our general and administrative expenses was primarily attributable to increased payroll expenses of approximately $13.8 million associated with additional employees to support our increased land, geoscience, drilling, completion, production, midstream, accounting and administration functions as a result of our continued growth. This increase was partially offset by an increase of capitalized general and administrative expenses of $3.1 million for the year ended December 31, 2019 . Our general and administrative expenses decrease d 9% on a unit-of-production basis to $3.31 per BOE for the year ended December 31, 2019 , as compared to $3.64 per BOE for the year ended December 31, 2018 , as the 27% increase in total oil equivalent production between the respective periods more than offset the 9% increase in our general and administrative expenses. +Interest expense. For the year ended December 31, 2019 , we incurred total interest expense of approximately $82.4 million . We capitalized approximately $8.5 million of our interest expense on certain qualifying projects for the year ended December 31, 2019 and expensed the remaining $73.9 million to operations. For the year ended December 31, 2018 , we incurred total interest expense of approximately $50.2 million . We capitalized $8.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2018 and expensed the remaining $41.3 million to operations. The increase in total interest expense for the year ended December 31, 2019 , as compared to the year ended December 31, 2018 , was primarily attributable to an increase in our average debt outstanding. In August and September 2018, we completed a tender offer and redemption of our $575.0 million aggregate principal amount of 6.875% senior notes due 2023 (the “2023 Notes”). In August 2018, we issued $750.0 million aggregate principal amount of 5.875% notes due 2026 (the “Original 2026 Notes”), and in October 2018, we issued an additional $300.0 million aggregate principal amount of 5.875% notes due 2026 (the “Additional 2026 Notes” and, together with the Original 2026 Notes, the “2026 Notes”), increasing our total senior notes outstanding to $1.05 billion at December 31, 2018 . +Prepayment premium on extinguishment of debt. For the year ended December 31, 2018, we incurred a prepayment premium on extinguishment of debt of $31.2 million resulting from the tender offer to purchase for cash and subsequent redemption of all of our 2023 Notes. There was no similar expense incurred for the year ended December 31, 2019 . +Total income tax provision (benefit). We recorded a total income tax provision of $35.5 million for the year ended December 31, 2019 . Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of permanent differences between book and taxable income and state taxes, primarily in New Mexico. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2020 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our 2020 capital expenditures through a combination of cash on hand, operating cash flows, performance incentives in connection with San Mateo, borrowings under our Credit Agreement (assuming availability under our borrowing base of $900.0 million) and borrowings under the San Mateo Credit Facility (assuming availability under the accordion feature of such facility to up to $400.0 million). In addition, in 2020, we expect to receive a portion of the $50.0 million capital carry Five Point agreed to provide to us in conjunction with the formation of San Mateo II. We continually evaluate other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to generate operating cash flows. +73 +Table of Contents +At December 31, 2019 , we had cash totaling approximately $40.0 million and restricted cash totaling approximately $25.1 million , most of which was associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +In October 2018, the lenders under our Credit Agreement, led by Royal Bank of Canada, completed their review of our proved oil and natural gas reserves at June 30, 2018. In connection with such review, we amended the Credit Agreement to, among other items, increase the maximum facility amount to $1.5 billion, increase the borrowing base to $850.0 million, increase the elected borrowing commitment to $500.0 million, extend the maturity to October 31, 2023, reduce borrowing rates by 0.25% per annum and set the maximum leverage ratio at 4.00 to 1.00. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment. +In April 2019, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves at December 31, 2018, and as a result, the borrowing base was increased to $900.0 million with the elected borrowing commitment remaining at $500.0 million. In October 2019, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves at June 30, 2019, and as a result, the borrowing base was affirmed at $900.0 million with the elected borrowing commitment remaining at $500.0 million. +In February 2020, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves at December 31, 2019, and as a result, the borrowing base was again affirmed at $900.0 million, and we increased the elected borrowing commitment from $500.0 million to $700.0 million. +In December 2018, San Mateo I entered into the San Mateo Credit Facility, a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent, and including all lenders in the Credit Agreement at that time. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which provides for potential increases to up to $400.0 million. The San Mateo Credit Facility is guaranteed by San Mateo I’s subsidiaries, secured by substantially all of San Mateo I’s assets, including real property, and is non-recourse to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries. +In June and October 2019, pursuant to the accordion feature, the lender commitments under the San Mateo Credit Facility were increased to $325.0 million and $375.0 million , respectively. +In 2019, we converted approximately $21.9 million of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin. +At December 31, 2019 , we had (i) $1.05 billion of outstanding 2026 Notes, (ii) $255.0 million in borrowings outstanding under the Credit Agreement and (iii) approximately $46.1 million in outstanding letters of credit issued pursuant to the Credit Agreement, and San Mateo I had $288.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. At February 25, 2020 , we had (x) $1.05 billion of outstanding 2026 Notes, (y) $255.0 million in borrowings outstanding under the Credit Agreement and (z) approximately $46.0 million in outstanding letters of credit issued pursuant to the Credit Agreement, and San Mateo I had $288.0 million in borrowings outstanding and approximately $16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2020 . We plan to operate six contracted drilling rigs drilling primarily oil and natural gas wells in the Delaware Basin throughout 2020 . Our 2020 estimated capital expenditure budget consists of $690.0 to $750.0 million for D/C/E capital expenditures and $85.0 to $105.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated combined 2020 capital expenditures of $190.0 to $235.0 million and also accounts for the remaining portions of the $50.0 million capital carry that Five Point agreed to provide to us in conjunction with the formation of San Mateo II. Substantially all of these 2020 estimated capital expenditures will be allocated to (i) the further delineation and development of our leasehold position, (ii) the continued construction of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2020 Delaware Basin drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a particular emphasis on drilling and completing a higher percentage of longer horizontal wells in 2020, including 74% with anticipated completed lateral lengths of two miles. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 19 months. The other three rigs are on short-term contracts with remaining obligations of 12 months or less. This affords us the ability to modify our drilling program as we may deem necessary based on changing commodity prices and other factors. +74 +Table of Contents +To narrow any potential difference between our 2020 capital expenditures and operating cash flows, we may divest portions of our non-core assets, particularly in the Haynesville shale and in parts of our South Texas positions (as we did in 2019, converting $21.9 million of non-core assets to cash), as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during 2020 . These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2020 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2020 . +Our 2020 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2020 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2020 and the hedges we currently have in place. For further discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2019 . See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” +75 +Table of Contents +Our cash flows for the years ended December 31, 2019, 2018 and 2017 are presented below. +Year Ended December 31, +2019 +2018 +2017 +(In thousands) +Net cash provided by operating activities +$ +552,042 +$ +608,523 +$ +299,125 +Net cash used in investing activities +(903,976 +) +(1,515,253 +) +(819,284 +) +Net cash provided by financing activities +333,078 +888,232 +408,499 +Net change in cash +$ +(18,856 +) +$ +(18,498 +) +$ +(111,660 +) +Cash Flows Provided by Operating Activities +Net cash provided by operating activities decreased by $56.5 million to $552.0 million for the year ended December 31, 2019 , as compared to net cash provided by operating activities of $608.5 million for the year ended December 31, 2018 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $586.6 million for the year ended December 31, 2019 from $544.1 million for the year ended December 31, 2018 . This increase was primarily attributable to higher oil and natural gas production, which was partially offset by lower oil and natural gas prices realized during the year ended December 31, 2019 , as compared to the year ended December 31, 2018 . Changes in our operating assets and liabilities between December 31, 2018 and December 31, 2019 resulted in a net decrease of approximately $98.9 million in net cash provided by operating activities for the year ended December 31, 2019 , as compared to the year ended December 31, 2018 . +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities decreased by $611.3 million to $904.0 million for the year ended December 31, 2019 from $1.52 billion for the year ended December 31, 2018 . This decrease in net cash used in investing activities was attributable to (i) a decrease of $627.6 million in oil and natural gas properties capital expenditures and (ii) an increase of $13.6 million in proceeds from sales of assets for the year ended December 31, 2019 , both as compared to the year ended December 31, 2018 . This decrease in oil and natural gas properties expenditures was partially offset by an increase of approximately $28.8 million in expenditures for midstream support equipment and facilities, which included the construction of a further expansion of the Black River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline infrastructure. Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2019 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin and our nine-well program in South Texas concluded in the first half of 2019. In 2018, we completed the BLM Acquisition, through which we acquired 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million. The absence of an acquisition of similar magnitude in 2019 was the primary reason for the significant decrease in net cash used in investing activities in 2019, as compared to 2018. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $333.1 million for the year ended December 31, 2019 , as compared to net cash provided by financing activities of $888.2 million for the year ended December 31, 2018 . The net cash provided by financing activities for the year ended December 31, 2019 was primarily attributable to net borrowings under our Credit Agreement of $215.0 million, borrowings under the San Mateo Credit Facility of $68.0 million , contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries of $77.3 million and contributions related to the formation of San Mateo I of $14.7 million . These cash inflows were partially offset by distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries of $39.2 million . We conducted no equity or senior notes offerings during the year ended December 31, 2019 , as compared to the year ended December 31, 2018 , during which we conducted an equity offering and two senior notes offerings, which was the primary reason for the significant change in cash provided by financing activities between the respective periods. +76 +Table of Contents +See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including our Credit Agreement, the San Mateo Credit Facility and the senior notes. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2019 , the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm transportation, gathering, processing and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2019 . +Payments Due by Period +Total +Less Than 1 Year +1-3 Years +3-5 Years +More Than 5 Years +(In thousands) +Contractual Obligations: +Revolving credit borrowings, including letters of credit (1) +$ +605,351 +$ +— +$ +— +$ +605,351 +$ +— +Senior unsecured notes (2) +1,050,000 +— +— +— +1,050,000 +Office leases +26,374 +4,001 +8,013 +8,529 +5,831 +Non-operated drilling commitments (3) +26,943 +26,943 +— +— +— +Drilling rig contracts (4) +41,681 +28,195 +13,486 +— +— +Asset retirement obligations (5) +36,211 +620 +3,104 +1,656 +30,831 +Natural gas transportation, gathering and processing agreements with non-affiliates (6) +645,984 +55,401 +134,857 +134,888 +320,838 +Gathering, processing and disposal agreements with San Mateo (7) +516,646 +— +65,267 +163,614 +287,765 +Natural gas engineering, construction and installation contract (8) +40,254 +40,254 +— +— +— +Total contractual cash obligations +$ +2,989,444 +$ +155,414 +$ +224,727 +$ +914,038 +$ +1,695,265 +__________________ +(1) +The amounts included in the table above represent principal maturities only. At December 31, 2019 , we had $255.0 million of borrowings outstanding under the Credit Agreement and approximately $46.1 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2023. At December 31, 2019 San Mateo I had $288.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of 3.28% and 3.55% (for the Credit Agreement and the San Mateo Credit Facility), respectively, at December 31, 2019 , the interest expense is expected to be approximately $8.4 million and $10.4 million each year until maturity. +(2) +The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of December 31, 2019 is expected to be approximately $61.7 million each year until maturity. +(3) +At December 31, 2019 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2019 . If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $26.9 million at December 31, 2019 , which we expect to incur within the next year. +(4) +We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) +The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2019 . +(6) +In late 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. In late 2017, we entered into an 18-year fixed-fee natural gas transportation agreement whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline in Eddy County, New Mexico. In late 2017, we also entered into a fixed-fee NGL transportation and fractionation agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing Plant. We have committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed in 2020. We have no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then we do not have any minimum volume commitments under the agreement. If the +77 +Table of Contents +counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then we will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If we do not meet our NGL volume commitment in any quarter during the seven-year commitment period, we will be required to pay a deficiency fee per gallon of NGL deficiency. The amounts in the table assume that the seven-year period containing minimum NGL volume commitments begins in 2020. In the second quarter of 2018, we entered into a 16-year, fixed-fee natural gas transportation agreement that begins on October 1, 2019 whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Additionally, in the second quarter of 2018, we entered into a short-term natural gas transportation agreement whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. In the second quarter of 2018, we entered into a 10-year, fixed-fee natural gas sales agreement whereby we committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date for such pipeline, which became operational in late September 2019. Lastly, in October 2019, we entered into a 15-year, fixed-fee natural gas transportation agreement whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(7) +In February 2017, in connection with the formation of San Mateo I, we dedicated our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and certain future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. In February 2019, in connection with the formation of San Mateo II, we dedicated our current and certain future leasehold interests in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(8) +Beginning in June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. +In 2019, oil prices generally declined from the prices we experienced in 2018 and remained significantly below their most recent highs in 2014. For the year ended December 31, 2019, oil prices averaged $57.01 per Bbl, as compared to $64.89 per Bbl for the year ended December 31, 2018, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. During 2019, oil prices began the year at $45.41 per Bbl, which was the low for the year, and increased steadily, reaching a high of $66.30 per Bbl in late April. Oil prices declined during the third quarter of 2019 before increasing again during the fourth quarter of 2019 to finish the year at $61.06 per Bbl. In early 2020, oil prices have been particularly volatile, ranging from a high of $65.00 per Bbl in early January to below $45.00 per Bbl in late February. +We realized a weighted average oil price of $54.34 per Bbl ($54.98 per Bbl including realized gains from oil derivatives) for our oil production for the year ended December 31, 2019, as compared to $57.04 per Bbl ($57.38 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2018. At February 25, 2020 , the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date had declined from year-end 2019, closing at $49.90 per Bbl, and was lower compared to $55.48 per Bbl on February 25, 2019. +Natural gas prices dropped significantly during much of 2019. For the year ended December 31, 2019, natural gas prices averaged $2.53 per MMBtu, as compared to $3.07 per MMbtu for the year ended December 31, 2018, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2019, natural gas prices began the year at $2.94 per MMBtu and reached a high of $3.59 per MMBtu in mid-January, before declining to low of $2.07 per MMBtu in early August and finishing the year at $2.19 per MMBtu. +We realized a weighted average natural gas price of $2.17 per Mcf ($2.18 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2019, as compared to $3.49 per Mcf ($3.46 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2018. As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average natural gas price. NGL prices were weaker in 2019, as compared to 2018. At February 25, 2020 , the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had declined further from year-end 2019, closing at $1.85 per MMBtu, and was significantly lower as compared to $2.84 per MMBtu at February 25, 2019. +The prices we receive for oil, natural gas and NGLs heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Recently, oil prices have experienced a significant decrease as a result of the perceived impact upon global demand for oil due to the outbreak of the +78 +Table of Contents +coronavirus. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically, and, as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. We are uncertain if oil and natural gas prices may rise from their current levels, and in fact, oil and natural gas prices may decrease in future periods. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. +In addition, the prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2019, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas. For the first nine months of 2019, most of our natural gas production from the Delaware Basin was sold based on prices established at the Waha Hub in far West Texas. At the end of September 2019, the GCX Pipeline became operational. We have secured firm natural gas transportation and sales on the GCX Pipeline for an average of approximately 110,000 to 115,000 MMBtu per day at a natural gas price based upon Houston Ship Channel pricing. +During the second quarter of 2018, the price differentials for oil sold in Midland and natural gas sold at Waha compared to the benchmark prices for oil and natural gas, respectively, began to widen significantly and continued to widen throughout most of the year. These widening basis differentials negatively impacted our oil and natural gas revenues in 2018 and throughout most of 2019. +During 2018, the Midland-Cushing (Oklahoma) oil price differential increased substantially from essentially no difference in the first quarter to as much as $16.00 per Bbl in late September but narrowed to about $5.00 per Bbl at the beginning of 2019. The Midland-Cushing (Oklahoma) oil price differential narrowed further to less than $1.00 per Bbl during the first quarter of 2019 but widened again during the second quarter to levels experienced at the beginning of the year. The Midland-Cushing (Oklahoma) oil price differential narrowed again in the third quarter of 2019, became positive late in the third quarter and remained positive throughout the fourth quarter of 2019. As of February 25, 2020, this oil price differential had remained positive in 2020, although it is possible that this differential could turn negative again at certain times during the remainder of 2020. +Our realized price for a portion of our Delaware Basin natural gas production is exposed to the Waha-Henry Hub basis differential. This natural gas price differential increased significantly throughout 2018 from about $0.50 per MMBtu at the beginning of the year to between $1.00 and $2.00 per MMBtu for most of 2018, but reaching highs of greater than $4.00 per MMBtu for a brief period near the end of the year. The natural gas price differential narrowed to between $1.00 and $2.00 per MMBtu at the beginning of 2019 and remained there throughout much of the first quarter. +The natural gas basis differentials widened significantly in April 2019 for a short period of time, including a few days when natural gas was being sold at Waha for negative prices as high as ($7.00) to ($9.00) per MMBtu on a daily market basis, resulting, in part, from a number of simultaneous outages and maintenance projects impacting major pipelines in the area. Natural gas prices at Waha were positive for most of the latter part of April 2019, but daily market prices for natural gas sold at Waha reached negative levels of ($2.00) to ($3.00) per MMBtu in late May. In response to these basis differentials, we temporarily shut in certain high gas-oil ratio wells and took other actions to mitigate the impact of these negative prices on our results. +During the second half of 2019, the Waha basis differentials improved, and natural gas prices at the Waha hub averaged approximately $1.00 per MMBtu for the final six months of the year. As a result, we did not need to shut in certain high gas-to-oil ratio wells or take other actions to curtail our Delaware Basin natural gas production during this period. Despite improving during the second half of 2019, beginning in the fourth quarter, the Waha basis differentials widened further at times, and natural gas prices at the Waha hub were slightly negative on certain days in late December 2019. In early 2020, the outlook for the Waha basis differentials has deteriorated further, with the futures markets indicating Waha basis differentials between $1.20 and $2.00 per MMBtu throughout 2020 as of mid-February. +Beginning in late September 2019, as the GCX Pipeline became operational, we began selling a majority of our produced Delaware Basin natural gas at Houston Ship Channel pricing, and we realized an improvement in the natural gas pricing received despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. Further, approximately 32% of our reported natural gas production in the third and fourth quarters of 2019 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas +79 +Table of Contents +volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. +These widening oil and natural gas basis differentials are largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. At February 25, 2020 , we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +We anticipate that the volatility in these oil and natural gas price differentials could persist throughout 2020 or longer until additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is completed. We can provide no assurances as to how long these volatile differentials may persist, and as noted above, these price differentials could widen further in future periods. Should we experience future periods of negative pricing for natural gas as we did during the second quarter of 2019, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials during 2020. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, in 2019 and 2020, separate bills were introduced in the New Mexico Senate proposing to add a surtax on natural gas processors and proposing to place a moratorium on hydraulic fracturing. In 2019, New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Although such bills have not passed, these and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. In addition, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry, recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2019 . +80 +Table of Contents +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related oil and natural gas reserves. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. These instruments typically consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a +81 +Table of Contents +call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. +In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized gain (loss) on derivatives.” Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under Revenues as “Realized gain (loss) on derivatives.” +Revenue Recognition +During the first quarter of 2018, we adopted Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve the financial reporting requirements for revenue from contracts with customers and converge these requirements with international standards. We adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on our consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows. +Prior to the adoption of ASC 606, we recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser. We followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on our actual proceeds from the oil and natural gas sold to purchasers. +We enter into contracts with customers to sell our oil and natural gas production. With the adoption of ASC 606, revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when our performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration we expect to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of our oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on our consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +Our natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of our natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas and transports the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if we elect to take in-kind the natural gas or NGLs, we sell the natural gas or NGLs to a third party. Under the fee-based contracts, we receive NGL and residue gas value, less the fee component, or are invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, +82 +Table of Contents +revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on our consolidated statements of operations. +We recognize midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. All midstream services revenues related to our working interest are eliminated in consolidation. Since we have a right to payment from our customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, we apply the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +We periodically enter into natural gas purchase transactions with third parties whereby we process a third party’s natural gas at the Black River Processing Plant and then purchase, and subsequently sell, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on our consolidated statements of operations as we act as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, we, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of our mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed, and we have no further obligation to the lessee. We record these payments as “Lease bonus - mineral acreage” revenues on our consolidated statements of operations. +Stock-Based Compensation +We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options (all of which were settled in the first quarter of 2020) and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock. +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and were reviewed quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations or capitalized in accordance with our policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on the date of the grant for awards issued under the 2003 Plan and on the trading day prior to the date of grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2019 . +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 8 to the consolidated +83 +Table of Contents +financial statements in this Annual Report for additional information of the impact of the 2017 Tax Cuts and Jobs Act to our consolidated financial statements. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” +Leases +On January 1, 2019, the Company began recording in the consolidated balance sheet certain of the Company’s compressor leases, drilling rig leases and office leases, which were previously considered operating leases and not reported on the Company’s consolidated balance sheets. The present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheet. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +Recent Accounting Pronouncements +See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of +84 +Table of Contents +a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2019 , The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2019 , we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil prices, each with an established price floor and ceiling. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by one or more of the costless collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. +During the year ended December 31, 2019 , we entered into various swap contracts to mitigate our exposure to price differences between NYMEX West Texas Intermediate Cushing and Argus West Texas Intermediate Midland crude oil. When the settlement price is below the fixed price established by one or more of these swaps, we receive from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by one or more of these swaps, we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. +See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2019 . Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2019 , we had outstanding borrowings of $255.0 million at an interest rate of 3.28% per annum under our Credit Agreement, $1.05 billion in Notes outstanding at a coupon rate of 5.875% per annum and $288.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 3.55% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, +85 +Table of Contents +which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 25, 2020 were The Bank of Nova Scotia and BMO Harris Financing (Bank of Montreal) (or affiliates thereof), which are lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2019, 2018 and 2017 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report beginning on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2019 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2019 as included herein. +86 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +87 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018 , the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019 , and the related notes (collectively, the consolidated financial statements), and our report dated March 2, 2020 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +March 2, 2020 +88 +Table of Contents +Item 9B. Other Information. +On September 28, 2012, Matador, as a guarantor, along with certain other guarantors thereto, MRC Energy Company, a wholly-owned subsidiary of Matador (“MRC”), as borrower, the lenders party thereto (the “Lenders”) and Royal Bank of Canada, as administrative agent, entered into the Credit Agreement. For a summary of key terms of the Credit Agreement, see Note 7 to the consolidated financial statements in this Annual Report, which description is incorporated herein by reference. On February 27, 2020, MRC, as borrower, entered into an amendment (the “Amendment”) to the Credit Agreement, and Matador reaffirmed its guaranty of MRC’s obligations under the Credit Agreement. The Amendment affirmed the $900.0 million borrowing base, increased the elected borrowing commitment from $500.0 million to $700.0 million and added two lenders. +The foregoing description of the Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of the Amendment, which is included in this Annual Report as Exhibit 10.55 and is incorporated herein by reference. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2020 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 3—Ratification of Appointment of KPMG LLP.” +. +89 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2019 and 2018 , Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017 . +2. Financial Statement Schedules : All other schedules for which provision is made in the applicable accounting regulation of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto. +3. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below. +Item 16. Form 10-K Summary. +None. +90 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).* +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018). +4.3 +First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018). +4.4 +Description of Capital Stock (filed herewith). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.8† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +91 +Table of Contents +10.10† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.11 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.12 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.13 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.14 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.15 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.16 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.17 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.18 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.19 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.20 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.21 +Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016). +10.22 +Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016). +10.23 +Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017) . +10.24† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +92 +Table of Contents +10.25† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.26† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.27† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.28† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.29† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.30† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.31† +Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.62 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.32† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.33† +Form of Letter Agreement between Matador Resources Company and certain directors modifying Restricted Stock Unit Award Agreements (incorporated by reference to Exhibit 10.64 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.34† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.35† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.36† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.37† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.38† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.39† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.40† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.41† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.42† +First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +93 +Table of Contents +10.43† +Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.44 +Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 9, 2018). +10.45 +Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of October 1, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 4, 2018). +10.46 +Thirteenth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 1, 2018). +10.47† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.48† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.49† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.50† +Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019). +10.51† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.52† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.53† +First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.54† +First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.55 +Fourteenth Amendment to Third Amended and Restated Credit Agreement, dated as of February 27, 2020, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +94 +Table of Contents +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +104 +Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101). +† +Indicates a management contract or compensatory plan or arrangement. +* +Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +95 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +March 2, 2020 +By: +/s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Joseph Wm. Foran +Chairman and Chief Executive Officer +March 2, 2020 +Joseph Wm. Foran +(Principal Executive Officer) +/s/ David E. Lancaster +Executive Vice President and Chief Financial Officer +March 2, 2020 +David E. Lancaster +(Principal Financial Officer) +/s/ Robert T. Macalik +Senior Vice President and Chief Accounting Officer +March 2, 2020 +Robert T. Macalik +(Principal Accounting Officer) +/s/ Reynald A. Baribault +Director +March 2, 2020 +Reynald A. Baribault +/s/ R. Gaines Baty +Director +March 2, 2020 +R. Gaines Baty +/s/ Craig T. Burkert +Director +March 2, 2020 +Craig T. Burkert +/s/ William M. Byerley +Director +March 2, 2020 +William M. Byerley +/s/ Matthew P. Clifton +Director +March 2, 2020 +Matthew P. Clifton +/s/ Monika U. Ehrman +Director +March 2, 2020 +Monika U. Ehrman +/s/ Julia P. Forrester Rogers +Director +March 2, 2020 +Julia P. Forrester Rogers +/s/ Timothy E. Parker +Director +March 2, 2020 +Timothy E. Parker +/s/ David M. Posner +Director +March 2, 2020 +David M. Posner +/s/ Kenneth L. Stewart +Director +March 2, 2020 +Kenneth L. Stewart +96 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or salt water. +Bcf . One billion cubic feet of natural gas. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differential . The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +97 +Table of Contents +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Lateral length . Length of the completed portion of a horizontal well. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or salt water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +98 +Table of Contents +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +99 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2019, 2018 and 2017 +Index +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2019 and 2018 +F-4 +Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017 +F-5 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017 +F-6 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017 +F-7 +Notes to Consolidated Financial Statements +F-8 +Unaudited Supplementary Information +F-46 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2019 and 2018 , the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2019 , and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018 , and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2019 , in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 2, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Change in Accounting Principle +As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update 2016‑02, Leases (Topic 842) , and related amendments. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +Assessment of the impact of estimated oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation +As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. For the year ended December 31, 2019 , the Company recorded depletion expense of evaluated oil and natural gas properties of $330.7 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company recorded $4.6 billion of gross evaluated oil and natural gas properties as of December 31, 2019. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present +F-2 +Table of Contents +value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. The Company’s internal reserves engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reserves engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company. +We identified the assessment of the impact of estimated oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves, as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive of market differentials. +The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s depletion and ceiling test processes, including controls related to the assumptions used to estimate proved reserves used in the respective calculations. We assessed the competence, capabilities, and objectivity of the Company’s internal reserves engineers, who estimated the proved reserves, and the external reserves engineers engaged by the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reserves engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reserves engineers’ estimate regarding future operating and development costs based on historical information. In addition, we compared the forecasted production volumes assumption used by the Company in the current period to historical production and we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast. We read the findings of the Company’s external reserves engineers in connection with our evaluation of the Company’s reserves estimates. We analyzed the depletion expense calculation for compliance with industry and regulatory standards, and recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +March 2, 2020 +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2019 +2018 +ASSETS +Current assets +Cash +$ +40,024 +$ +64,545 +Restricted cash +25,104 +19,439 +Accounts receivable +Oil and natural gas revenues +95,228 +68,161 +Joint interest billings +67,546 +61,831 +Other +26,639 +16,159 +Derivative instruments +— +49,929 +Lease and well equipment inventory +10,744 +17,564 +Prepaid expenses and other current assets +13,207 +8,057 +Total current assets +278,492 +305,685 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated +4,557,265 +3,780,236 +Unproved and unevaluated +1,126,992 +1,199,511 +Midstream properties +643,903 +428,025 +Other property and equipment +27,021 +22,041 +Less accumulated depletion, depreciation and amortization +( 2,655,586 +) +( 2,306,949 +) +Net property and equipment +3,699,595 +3,122,864 +Other assets +Deferred income taxes +— +20,457 +Other long-term assets +91,589 +6,512 +Total other assets +91,589 +26,969 +Total assets +$ +4,069,676 +$ +3,455,518 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable +$ +25,230 +$ +66,970 +Accrued liabilities +200,695 +170,855 +Royalties payable +85,193 +64,776 +Amounts due to affiliates +19,606 +13,052 +Derivative instruments +1,897 +— +Advances from joint interest owners +14,837 +10,968 +Amounts due to joint ventures +486 +2,373 +Other current liabilities +51,828 +1,028 +Total current liabilities +399,772 +330,022 +Long-term liabilities +Borrowings under Credit Agreement +255,000 +40,000 +Borrowings under San Mateo Credit Facility +288,000 +220,000 +Senior unsecured notes payable +1,039,416 +1,037,837 +Asset retirement obligations +35,592 +29,736 +Derivative instruments +1,984 +83 +Deferred income taxes +37,329 +13,221 +Other long-term liabilities +43,131 +4,962 +Total long-term liabilities +1,700,452 +1,345,839 +Commitments and contingencies (Note 14) +Shareholders’ equity +Common stock — $0.01 par value, 160,000,000 shares authorized; 116,644,246 and 116,374,503 shares issued; and 116,642,899 and 116,353,590 shares outstanding, respectively +1,166 +1,164 +Additional paid-in capital +1,981,014 +1,924,408 +Accumulated deficit +( 148,500 +) +( 236,277 +) +Treasury stock, at cost, 1,347 and 20,913 shares, respectively +( 26 +) +( 415 +) +Total Matador Resources Company shareholders’ equity +1,833,654 +1,688,880 +Non-controlling interest in subsidiaries +135,798 +90,777 +Total shareholders’ equity +1,969,452 +1,779,657 +Total liabilities and shareholders’ equity +$ +4,069,676 +$ +3,455,518 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +Year Ended December 31, +2019 +2018 +2017 +Revenues +Oil and natural gas revenues +$ +892,325 +$ +800,700 +$ +528,684 +Third-party midstream services revenues +59,110 +21,920 +10,198 +Sales of purchased natural gas +74,769 +7,071 +— +Lease bonus - mineral acreage +1,711 +2,489 +— +Realized gain (loss) on derivatives +9,482 +2,334 +( 4,321 +) +Unrealized (loss) gain on derivatives +( 53,727 +) +65,085 +9,715 +Total revenues +983,670 +899,599 +544,276 +Expenses +Production taxes, transportation and processing +92,273 +76,138 +58,275 +Lease operating +117,305 +92,966 +67,313 +Plant and other midstream services operating +36,798 +24,609 +13,039 +Purchased natural gas +69,398 +6,635 +— +Depletion, depreciation and amortization +350,540 +265,142 +177,502 +Accretion of asset retirement obligations +1,822 +1,530 +1,290 +General and administrative +80,054 +69,308 +66,016 +Total expenses +748,190 +536,328 +383,435 +Operating income +235,480 +363,271 +160,841 +Other income (expense) +Net (loss) gain on asset sales and inventory impairment +( 967 +) +( 196 +) +23 +Interest expense +( 73,873 +) +( 41,327 +) +( 34,565 +) +Prepayment premium on extinguishment of debt +— +( 31,226 +) +— +Other (expense) income +( 2,126 +) +1,551 +3,551 +Total other expense +( 76,966 +) +( 71,198 +) +( 30,991 +) +Income before income taxes +158,514 +292,073 +129,850 +Income tax provision (benefit) +Current +— +( 455 +) +( 8,157 +) +Deferred +35,532 +( 7,236 +) +— +Total income tax provision (benefit) +35,532 +( 7,691 +) +( 8,157 +) +Net income +122,982 +299,764 +138,007 +Net income attributable to non-controlling interest in subsidiaries +( 35,205 +) +( 25,557 +) +( 12,140 +) +Net income attributable to Matador Resources Company shareholders +$ +87,777 +$ +274,207 +$ +125,867 +Earnings per common share +Basic +$ +0.75 +$ +2.41 +$ +1.23 +Diluted +$ +0.75 +$ +2.41 +$ +1.23 +Weighted average common shares outstanding +Basic +116,555 +113,580 +102,029 +Diluted +117,063 +113,691 +102,543 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2019, 2018 and 2017 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital +Accumulated deficit +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders ’ equity +Common Stock +Shares +Amount +Shares +Amount +Balance at January 1, 2017 +99,519 +$ +995 +$ +1,325,481 +$ +( 636,351 +) +6 +$ +— +$ +690,125 +$ +1,320 +$ +691,445 +Issuance of common stock pursuant to employee stock compensation plan +530 +5 +( 5 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +77 +1 +( 1 +) +— +— +— +— +— +— +Issuance of common stock pursuant to public offering +8,000 +80 +208,640 +— +— +— +208,720 +— +208,720 +Cost to issue equity +— +— +( 280 +) +— +— +— +( 280 +) +— +( 280 +) +Stock-based compensation expense related to equity-based awards including amounts capitalized +— +— +19,594 +— +— +— +19,594 +— +19,594 +Stock options exercised, net of options forfeited in net share settlements +514 +5 +( 1,189 +) +— +— +— +( 1,184 +) +— +( 1,184 +) +Restricted stock forfeited +— +— +— +— +123 +( 1,658 +) +( 1,658 +) +— +( 1,658 +) +Purchase of non-controlling interest of less-than-wholly-owned subsidiary +— +— +( 1,250 +) +— +— +— +( 1,250 +) +( 1,403 +) +( 2,653 +) +Contributions related to formation of San Mateo I (see Note 6) +— +— +116,622 +— +— +— +116,622 +54,878 +171,500 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +44,100 +44,100 +Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries +— +— +— +— +— +— +— +( 10,045 +) +( 10,045 +) +Cancellation of treasury stock +( 126 +) +( 1 +) +( 1,588 +) +— +( 126 +) +1,589 +— +— +— +Current period net income +— +— +— +125,867 +— +— +125,867 +12,140 +138,007 +Balance at December 31, 2017 +108,514 +1,085 +1,666,024 +( 510,484 +) +3 +( 69 +) +1,156,556 +100,990 +1,257,546 +Issuance of common stock pursuant to employee stock compensation plan +759 +8 +( 8 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +81 +1 +( 1 +) +— +— +— +— +— +— +Issuance of common stock pursuant to public offering +7,000 +70 +226,542 +— +— +— +226,612 +— +226,612 +Cost to issue equity +— +— +( 204 +) +— +— +— +( 204 +) +— +( 204 +) +Stock-based compensation expense related to equity-based awards including amounts capitalized +— +— +22,660 +— +— +— +22,660 +— +22,660 +Stock options exercised, net of options forfeited in net share settlements +179 +2 +( 1,269 +) +— +— +— +( 1,267 +) +— +( 1,267 +) +Restricted stock forfeited +— +— +— +— +176 +( 4,384 +) +( 4,384 +) +— +( 4,384 +) +Contributions related to formation of San Mateo I (see Note 6) +— +— +14,700 +— +— +— +14,700 +— +14,700 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +85,750 +85,750 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +( 121,520 +) +( 121,520 +) +Cancellation of treasury stock +( 158 +) +( 2 +) +( 4,036 +) +— +( 158 +) +4,038 +— +— +— +Current period net income +— +— +— +274,207 +— +— +274,207 +25,557 +299,764 +Balance at December 31, 2018 +116,375 +$ +1,164 +$ +1,924,408 +$ +( 236,277 +) +21 +$ +( 415 +) +$ +1,688,880 +$ +90,777 +$ +1,779,657 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital +Accumulated deficit +Treasury Stock +Non-controlling interest in subsidiaries +Total shareholders ’ equity +Common Stock +Shares +Amount +Shares +Amount +Balance at December 31, 2018 +116,375 +$ +1,164 +$ +1,924,408 +$ +( 236,277 +) +21 +$ +( 415 +) +$ +1,688,880 +$ +90,777 +$ +1,779,657 +Issuance of common stock pursuant to employee stock compensation plan +240 +2 +( 2 +) +— +— +— +— +— +— +Issuance of common stock pursuant to directors’ and advisors’ compensation plan +50 +— +— +— +— +— +— +— +— +Stock-based compensation expense related to equity-based awards including amounts capitalized +— +— +23,396 +— +— +— +23,396 +— +23,396 +Stock options exercised, net of options forfeited in net share settlements +220 +2 +3,298 +— +— +— +3,300 +— +3,300 +Liability-based stock option awards settled +1 +— +11 +— +— +— +11 +— +11 +Restricted stock forfeited +— +— +— +— +222 +( 3,691 +) +( 3,691 +) +— +( 3,691 +) +Contribution related to formation of San Mateo I, net of tax of $3.1 million (See Note 6) +— +— +11,613 +— +— +— +11,613 +— +11,613 +Contribution of property related to formation of San Mateo II (See Note 6) +— +— +( 506 +) +— +— +— +( 506 +) +506 +— +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $5.9 million (See Note 6) +— +— +22,874 +— +— +— +22,874 +48,510 +71,384 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries +— +— +— +— +— +— +— +( 39,200 +) +( 39,200 +) +Cancellation of treasury stock +( 242 +) +( 2 +) +( 4,078 +) +— +( 242 +) +4,080 +— +— +— +Current period net income +— +— +— +87,777 +— +— +87,777 +35,205 +122,982 +Balance at December 31, 2019 +116,644 +$ +1,166 +$ +1,981,014 +$ +( 148,500 +) +1 +$ +( 26 +) +$ +1,833,654 +$ +135,798 +$ +1,969,452 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2019 +2018 +2017 +Operating activities +Net income +$ +122,982 +$ +299,764 +$ +138,007 +Adjustments to reconcile net income to net cash provided by operating activities +Unrealized loss (gain) on derivatives +53,727 +( 65,085 +) +( 9,715 +) +Depletion, depreciation and amortization +350,540 +265,142 +177,502 +Accretion of asset retirement obligations +1,822 +1,530 +1,290 +Stock-based compensation expense +18,505 +17,200 +16,654 +Prepayment premium on extinguishment of debt +— +31,226 +— +Deferred income tax provision (benefit) +35,532 +( 7,236 +) +— +Amortization of debt issuance cost +2,484 +1,357 +468 +Net loss (gain) on asset sales and inventory impairment +967 +196 +( 23 +) +Changes in operating assets and liabilities +Accounts receivable +( 43,261 +) +( 4,934 +) +( 82,549 +) +Lease and well equipment inventory +4,777 +( 12,176 +) +( 3,623 +) +Prepaid expenses and other current assets +( 4,844 +) +( 1,770 +) +( 2,960 +) +Other long-term assets +678 +3,418 +( 6,425 +) +Accounts payable, accrued liabilities and other current liabilities +( 19,004 +) +68,647 +33,559 +Royalties payable +20,417 +3,418 +37,370 +Advances from joint interest owners +3,869 +8,179 +1,089 +Other long-term liabilities +2,851 +( 353 +) +( 1,519 +) +Net cash provided by operating activities +552,042 +608,523 +299,125 +Investing activities +Oil and natural gas properties capital expenditures +( 730,161 +) +( 1,357,802 +) +( 699,445 +) +Midstream capital expenditures +( 192,035 +) +( 163,222 +) +( 115,128 +) +Expenditures for other property and equipment +( 3,701 +) +( 2,562 +) +( 5,688 +) +Proceeds from sale of assets +21,921 +8,333 +977 +Net cash used in investing activities +( 903,976 +) +( 1,515,253 +) +( 819,284 +) +Financing activities +Repayments of borrowings +( 35,000 +) +( 370,000 +) +— +Borrowings under Credit Agreement +250,000 +410,000 +— +Borrowings under San Mateo Credit Facility +68,000 +220,000 +— +Cost to enter into or amend credit facilities +( 1,443 +) +( 3,077 +) +— +Proceeds from issuance of senior unsecured notes +— +1,051,500 +— +Cost to issue senior unsecured notes +— +( 14,098 +) +— +Purchase of senior unsecured notes +— +( 605,780 +) +— +Proceeds from issuance of common stock +— +226,612 +208,720 +Cost to issue equity +— +( 204 +) +( 280 +) +Proceeds from stock options exercised +3,300 +815 +2,920 +Contributions related to formation of San Mateo I +14,700 +14,700 +171,500 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries +77,330 +85,750 +44,100 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries +( 39,200 +) +( 121,520 +) +( 10,045 +) +Taxes paid related to net share settlement of stock-based compensation +( 3,691 +) +( 6,466 +) +( 5,763 +) +Purchase of non-controlling interest of less-than-wholly-owned subsidiary +— +— +( 2,653 +) +Cash paid under financing lease obligations +( 918 +) +— +— +Net cash provided by financing activities +333,078 +888,232 +408,499 +Decrease in cash and restricted cash +( 18,856 +) +( 18,498 +) +( 111,660 +) +Cash and restricted cash at beginning of year +83,984 +102,482 +214,142 +Cash and restricted cash at end of year +$ +65,128 +$ +83,984 +$ +102,482 +Supplemental disclosures of cash flow information (Note 15) +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2019, 2018 and 2017 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint ventures, San Mateo Midstream, LLC (“San Mateo I”) and San Mateo Midstream II, LLC (“San Mateo II” and, together with San Mateo I, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +Change in Accounting Principles +Leases. During the first quarter of 2019, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and the amendments provided for in ASU 2018-11, Leases (Topic 842) , which require the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that the Company chose to apply. These practical expedients relate to (i) the identification and classification of leases that commenced before the effective date, (ii) the treatment of initial direct costs for leases that commenced before the effective date, (iii) the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset and (iv) the ability to initially apply the new lease standard at the adoption date. During the first quarter of 2019, the Company also adopted ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient, and, as a result, the Company began evaluating land easements that are entered into or modified after December 31, 2018. See Note 4 for additional disclosures related to leases. +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The adoption of these ASUs resulted in the Company recording in the consolidated balance sheet beginning January 1, 2019 certain of the Company’s compressor leases, drilling rig leases and office leases, which were previously considered operating leases and not reported on the Company’s consolidated balance sheets. As such, upon adoption, the Company recorded (i) long-term right of use assets of $ 62.3 million , which are included in “Other assets” and “Other property and equipment,” and (ii) net right of use liabilities of $ 62.3 million , which are included in “Other current liabilities” and “Other long-term liabilities.” There was no cumulative-effect adjustment to the opening balance of accumulated deficit as a result of the adoption of these ASUs. +Stock Compensation. During the first quarter of 2019, the Company also adopted ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting , which extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Previously, the Company accounted for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards was recalculated each reporting period. Upon adoption, all such awards are now measured at fair value on the grant date, and the resulting expense is recognized on a straight-line basis over the awards’ vesting periods. The transitional guidance requires entities to remeasure all unvested awards that are being accounted for under ASC 505-50 as liability instruments as of the beginning of the year in which this ASU is adopted. Adoption of this ASU did not have a material impact on the Company’s consolidated financial statements. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (See “Revenues” below.) In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2019 , two significant purchasers accounted for 67 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 53 % ) and BP America Production Company ( 14 % ). For the year ended December 31, 2018 , four significant purchasers accounted for 60 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 19 % ), BP America Production Company ( 15 % ), Occidental Energy Marketing, Inc. ( 14 % ) and Western Refining Crude Oil ( 12 % ). For the year ended December 31, 2017 , four significant purchasers accounted for 60 % of the Company’s total oil, natural gas and NGL revenues: Occidental Energy Marketing, Inc. ( 23 % ), Plains Marketing, L.P. ( 14 % ), Shell Trading (US) Company ( 12 % ) and Western Refining Crude Oil ( 11 % ). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2019, 2018 and 2017 , approximately 31 % , 34 % and 43 % , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $ 31.1 million , $ 28.3 million and $ 23.1 million of its general and administrative costs into oil and natural gas properties in 2019 , 2018 and 2017 , respectively. The Company capitalized $ 7.6 million , $ 8.8 million and $ 7.3 million of its interest expense into oil and natural gas properties for the years ended December 31, 2019, 2018 and 2017 , respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2019 , 2018 and 2017, the Company recorded depletion expense of $ 330.7 million , $ 251.8 million and $ 170.3 million , respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10 % , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10 % discount factor is used to determine the present value of future net revenues. For the period from January through December 2019 , these average oil and natural gas prices were $ 52.19 per Bbl and $ 2.58 per MMBtu, respectively. For the period from January through December 2018 , these average oil and natural gas prices were $ 62.04 per Bbl and $ 3.10 per MMBtu, respectively. For the period from January through December 2017 , these average oil and natural gas prices were $ 47.79 per Bbl and $ 2.98 per MMBtu, respectively. In estimating the present value of after-tax future +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the years ended December 31, 2019, 2018 and 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2019, 2018 and 2017. +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream Properties and Other Property and Equipment +Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years ) using the straight-line method. The Company capitalized $ 1.8 million and $ 1.6 million of general and administrative costs into midstream properties in 2019 and 2018, respectively. The Company did not capitalize any general and administrative costs into midstream properties in 2017. The Company capitalized $ 0.9 million of interest expense into midstream properties for the year ended December 31, 2019. The Company did not capitalize any interest expense into midstream properties for the years ended December 31, 2018 and 2017. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment. +Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Revenues +The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606, Revenue from Contracts with Customers (Topic 606) . Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2019 and 2018 (in thousands). +Year Ended December 31, +2019 +2018 +Revenues from contracts with customers +$ +1,026,204 +$ +829,691 +Lease bonus - mineral acreage +1,711 +2,489 +Realized gain on derivatives +9,482 +2,334 +Unrealized (loss) gain on derivatives +( 53,727 +) +65,085 +Total revenues +$ +983,670 +$ +899,599 +Year Ended December 31, +2019 +2018 +Oil revenues +$ +759,811 +$ +635,554 +Natural gas revenues +132,514 +165,146 +Third-party midstream services revenues +59,110 +21,920 +Sales of purchased natural gas +74,769 +7,071 +Total revenues from contracts with customers +$ +1,026,204 +$ +829,691 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized on a straight-line basis over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. The Company accounts for all outstanding stock options granted under the Company’s 2003 Stock and Incentive Plan (the “2003 Plan”) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options. As the stock options accounted for as liability-based awards are fully vested, changes in the fair value of the awards are recognized until the awards are settled as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. All such stock options that were outstanding as of December 31, 2019 were settled in the first quarter of 2020. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2003 Plan and the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). +The Company’s consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017 include a stock-based compensation (non-cash) expense of $ 18.5 million , $ 17.2 million and $ 16.7 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $ 1.4 million , $ 1.6 million and $ 3.0 million in 2019 , 2018 and 2017 , respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of operations for the year ended December 31, 2019 also includes $ 3.2 million related to liability-based awards expected to be settled in cash. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2019, 2018 and 2017 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2019, 2018 and 2017 . +On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changed U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The Tax Cuts and Jobs Act reduced the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per share data). +Year Ended December 31, +2019 +2018 +2017 +Net income attributable to Matador Resources Company shareholders — numerator +$ +87,777 +$ +274,207 +$ +125,867 +Weighted average common shares outstanding — denominator +Basic +116,555 +113,580 +102,029 +Dilutive effect of options and restricted stock units +508 +111 +514 +Diluted weighted average common shares outstanding +117,063 +113,691 +102,543 +Earnings per common share attributable to Matador Resources Company shareholders +Basic +$ +0.75 +$ +2.41 +$ +1.23 +Diluted +$ +0.75 +$ +2.41 +$ +1.23 +A total of 2.6 million , 1.6 million and 1.0 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2019 , 2018 and 2017 , respectively, because their effects were anti-dilutive. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2019 were with The Bank of Nova Scotia and BMO Harris Financing, Inc. (Bank of Montreal) (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Income Taxes. In December 2019, the Financial Accounting Standards Board issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes , which removes certain exceptions to the general principles in Topic 740 and provides clarifications related to franchise taxes, transactions with a government that result in a step-up in the tax basis of goodwill, allocation of current and deferred income tax expense and the annual effective tax rate. This ASU is effective January 1, 2021, and its adoption is not expected to have a material impact on the Company’s consolidated financial statements. +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2019 and 2018 (in thousands). +December 31, +2019 +2018 +Oil and natural gas properties +Evaluated (subject to amortization) +$ +4,557,265 +$ +3,780,236 +Unproved and unevaluated (not subject to amortization) +1,126,992 +1,199,511 +Total oil and natural gas properties +5,684,257 +4,979,747 +Accumulated depletion +( 2,603,681 +) +( 2,273,010 +) +Net oil and natural gas properties +3,080,576 +2,706,737 +Midstream properties +Midstream equipment and facilities +643,903 +428,025 +Accumulated depreciation +( 38,473 +) +( 24,351 +) +Net midstream properties +605,430 +403,674 +Other property and equipment +Furniture, fixtures and other equipment +9,170 +7,047 +Software +8,099 +8,039 +Leasehold improvements +9,752 +6,955 +Total other property and equipment +27,021 +22,041 +Accumulated depreciation +( 13,432 +) +( 9,588 +) +Net other property and equipment +13,589 +12,453 +Net property and equipment +$ +3,699,595 +$ +3,122,864 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2019 and the year in which these costs were incurred (in thousands). +Description +2019 +2018 +2017 +2016 and prior +Total +Costs incurred for +Property acquisition +$ +43,795 +$ +556,415 +$ +204,425 +$ +258,296 +$ +1,062,931 +Exploration wells +10,814 +171 +361 +352 +11,698 +Development wells +52,144 +149 +70 +— +52,363 +Total +$ +106,753 +$ +556,735 +$ +204,856 +$ +258,648 +$ +1,126,992 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2019 are related to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +On September 12, 2018, the Company announced the successful acquisition of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $ 387 million in the Bureau of Land Management New Mexico Oil and Gas +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”). The BLM Acquisition was responsible for a significant portion of the Company’s property acquisition costs in 2018. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $ 64.1 million at December 31, 2019 . Of this total, $ 11.7 million was associated with exploration wells and $ 52.4 million was associated with development wells. The Company anticipates that most of the $ 64.1 million associated with these wells in progress at December 31, 2019 will be transferred to the amortization base during 2020 . Unproved and unevaluated property costs for exploration and development wells incurred from 2016 through 2018 are costs related to the advanced preparation for wells that we intend to drill in the future. +NOTE 4 — LEASES +The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheet. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rate used for the year ended December 31, 2019 was 3.52 % and 3.70 % for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the year ended December 31, 2019 (in thousands). Lease payments represent gross payments to vendors, which, for certain of our operating assets, are partially offset by amounts received from other working interest owners in our operated wells. +Year Ended +December 31, 2019 +Operating leases +Lease operating +$ +11,877 +Plant and other midstream services +110 +General and administrative +3,209 +Total operating leases (1) +15,196 +Short-term leases +Lease operating +10,441 +Plant and other midstream services +4,983 +General and administrative +27 +Total short-term leases (2)(3) +15,451 +Financing leases +Depreciation of assets +976 +Interest on lease liabilities +134 +Total financing leases +1,110 +Total lease expense +$ +31,757 +_____________________ +(1) +Does not include gross payments related to drilling rig leases of $ 28.1 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . +(2) +These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheet as they are short-term leases. +(3) +Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $ 90.3 million for the year ended December 31, 2019 that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheet at December 31, 2019 . +The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2019 (in thousands). +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 4 — LEASES — Continued +December 31, 2019 +Operating leases +Other long-term assets +$ +85,668 +Other current liabilities +$ +( 50,164 +) +Other long-term liabilities +( 41,459 +) +Total operating lease liabilities +$ +( 91,623 +) +Financing leases +Other property and equipment, at cost +$ +2,677 +Accumulated depreciation +( 1,324 +) +Net property and equipment +$ +1,353 +Other current liabilities +$ +( 799 +) +Other long-term liabilities +( 524 +) +Total financing lease liabilities +$ +( 1,323 +) +The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2019 (in thousands). +Year Ended December 31, 2019 +Cash paid related to lease liabilities +Operating cash payments for operating leases +$ +14,941 +Investing cash payments for operating leases +$ +28,034 +Financing cash payments for financing leases +$ +918 +Right of use assets obtained in exchange for lease obligations entered into during the period +Operating leases +$ +59,740 +Financing leases +$ +597 +The following table presents the maturities of lease liabilities at December 31, 2019 (in years). +Weighted-Average Remaining Lease Term +December 31, 2019 +Operating leases +2.7 +Financing leases +2.1 +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 4 — LEASES — Continued +The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2019 and 2018 , respectively (in thousands). +December 31, 2019 +Operating Leases +Financing Leases +2020 +$ +50,164 +$ +799 +2021 +27,279 +517 +2022 +5,010 +179 +2023 +4,177 +— +2024 +4,217 +— +Thereafter +5,716 +— +Total lease payments +96,563 +1,495 +Less imputed interest +( 4,940 +) +( 172 +) +Total lease obligations +91,623 +1,323 +Less current obligations +( 50,164 +) +( 799 +) +Long-term lease obligations +$ +41,459 +$ +524 +December 31, 2018 +Operating Leases +Financing Leases +2019 +$ +39,457 +$ +1,240 +2020 +12,009 +913 +2021 +3,513 +534 +2022 +3,209 +455 +2023 +3,234 +— +Thereafter +7,680 +— +Total lease payments +69,102 +3,142 +Less imputed interest +( 4,300 +) +( 130 +) +Total lease obligations +64,802 +3,012 +Less current obligations +( 39,457 +) +( 1,240 +) +Long-term lease obligations +$ +25,345 +$ +1,772 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS +In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +F-20 +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS — Continued +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2019 and 2018 (in thousands). +Year Ended December 31, +2019 +2018 +Beginning asset retirement obligations +$ +31,086 +$ +26,256 +Liabilities incurred during period +3,811 +3,566 +Liabilities settled during period +( 155 +) +( 708 +) +Revisions in estimated cash flows +1,792 +442 +Divestitures during the period +( 2,145 +) +— +Accretion expense +1,822 +1,530 +Ending asset retirement obligations +36,211 +31,086 +Less: current asset retirement obligations (1) +( 619 +) +( 1,350 +) +Long-term asset retirement obligations +$ +35,592 +$ +29,736 +__________________ +(1) +Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2019 and 2018 . +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES +Joint Ventures +On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo I, a joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). The midstream assets contributed to San Mateo I include (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo I’s other assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of San Mateo. +The Company and Five Point own 51 % and 49 % of San Mateo I, respectively. Five Point provided initial cash consideration of $ 176.4 million to San Mateo I in exchange for its 49 % interest. Approximately $ 171.5 million of this cash contribution by Five Point was distributed by San Mateo I to the Company as a special distribution. The Company earned, and Five Point paid to the Company, $ 14.7 million in performance incentives during each of the twelve months ended December 31, 2019 and 2018. As of February 28, 2020 , the Company had received an additional $ 14.7 million in performance incentives from Five Point and may earn an additional $ 29.4 million in performance incentives over the next two years . These performance incentives are recorded as additional contributions related to the formation of the San Mateo I as they are received. The Company contributed the Delaware Midstream Assets and $ 5.1 million in cash to San Mateo I in exchange for its 51 % interest. San Mateo I is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo I being accounted for as a non-controlling interest. +The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas to San Mateo I pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area to San Mateo I pursuant to a 15 -year, fixed-fee natural gas processing agreement (see Note 14). +On February 25, 2019, the Company announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point designed to expand the Company’s midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51 % by the Company and 49 % by Five Point. In addition, Five Point has committed to pay $ 125 million of the first $ 150 million of capital expenditures incurred by San Mateo II to develop facilities in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area. Upon formation of San Mateo II, in the first quarter of 2019, the Company contributed $ 1.0 million of property to San Mateo II. During the year ended December 31, 2019, the Company contributed $ 15.5 million of cash, and Five Point contributed $ 69.0 million of cash, of which $ 28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was therefore recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $ 5.9 million deferred +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +tax impact to Matador related to this equity contribution. In addition, the Company has the ability to earn up to $ 150.0 million in deferred performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. +In connection with the formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil, natural gas and salt water gathering, natural gas processing and salt water disposal agreements (see Note 14). +Divestitures +During 2019, we converted approximately $ 21.9 million of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin. +NOTE 7 — DEBT +At December 31, 2019 , the Company had $ 1.05 billion of outstanding senior notes due 2026, $ 255.0 million in borrowings outstanding under its revolving credit facility and approximately $ 46.1 million in outstanding letters of credit issued pursuant to its revolving credit facility. At December 31, 2019 , San Mateo I had $ 288.0 million in borrowings outstanding under its revolving credit facility and approximately $ 16.2 million in outstanding letters of credit issued pursuant to its revolving credit facility. +Credit Agreements +MRC Energy Company +On September 28, 2012 , the Company amended and restated its revolving credit facility with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company, a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80 % of the Company’s proved oil and natural gas properties and by the equity interests of certain of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. The Credit Agreement matures October 31, 2023. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. +In October 2018, the lenders under the Credit Agreement completed their review of the Company’s proved oil and natural gas reserves at June 30, 2018. In connection with such review, the Company amended the Credit Agreement to, among other items, increase the maximum facility amount to $1.5 billion, increase the borrowing base to $850.0 million, increase the elected borrowing commitment to $500.0 million, extend the maturity to October 31, 2023, reduce borrowing rates by 0.25% per annum and set the maximum leverage ratio at 4.00 to 1.00. +In April 2019, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2018, and as a result, the borrowing base was increased from $ 850.0 million to $ 900.0 million . In October 2019, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2019, and as a result, the borrowing base was affirmed at $ 900.0 million . The Company elected to keep the borrowing commitment at $ 500.0 million , and the maximum facility amount remained $ 1.5 billion . +In February 2020, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2019, and as a result, the borrowing base was again affirmed at $ 900.0 million . The Company elected to increase the borrowing commitment from $ 500.0 million to $ 700.0 million , and the maximum facility amount remained $ 1.5 billion . This February 2020 redetermination constituted the regularly scheduled May 1 redetermination. Borrowings under the Credit +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 7 — DEBT — Continued +Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment. +In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +Total deferred loan costs were $ 1.6 million at December 31, 2019 , and these costs are being amortized over the term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 3.28 % at December 31, 2019. At December 31, 2019 and February 25, 2020 , the Company had $ 255.0 million and $ 255.0 million in borrowings outstanding under the Credit Agreement and approximately $ 46.1 million and $ 46.0 million in outstanding letters of credit issued pursuant to the Credit Agreement, respectively. +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50 % and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0 % plus, in each case, an amount ranging from 0.25 % to 1.25 % per annum depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25 % to 2.25 % per annum depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. If the Company has outstanding borrowings under the Credit Agreement and interest rates increase, so will the Company’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375 % to 0.50 % per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $ 50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of the Company’s assets; +• +enter into commodity hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; +• +engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and +• +take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 7 — DEBT — Continued +• +bankruptcy or insolvency events involving the Company or its subsidiaries; and +• +a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2019 . +San Mateo Midstream, LLC +On December 19, 2018, San Mateo I entered into a $ 250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and including all lenders party to the Credit Agreement at that time. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which provides for potential increases to up to $ 400.0 million . The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, as well as San Mateo II and its subsidiaries, but is guaranteed by San Mateo I’s subsidiaries and secured by substantially all of San Mateo I’s assets, including real property. In June and October 2019, pursuant to the accordion feature, the lender commitments under the San Mateo Credit Facility were increased to $ 325.0 million and $ 375.0 million , respectively. +Total deferred loan costs were $ 2.7 million at December 31, 2019 , and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo I’s effective interest rate under the San Mateo Credit Facility was 3.55 % at December 31, 2019. At both December 31, 2019 and February 25, 2020 , San Mateo I had $ 288.0 million in borrowings outstanding under the San Mateo Credit Facility and $ 16.2 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo I borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50 % and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0 % plus, in each case, an amount ranging from 0.50 % to 1.50 % per annum depending on San Mateo I’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo I borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50 % to 2.50 % per annum depending on San Mateo I’s Consolidated Total Leverage Ratio. If San Mateo I has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo I’s interest costs, which may have a material adverse effect on San Mateo I’s results of operations and financial condition. +A commitment fee of 0.30 % to 0.50 % per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo I to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo I to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo I’s consolidated interest expense, of 2.50 or more. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo I’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• +incur indebtedness or grant liens on any of San Mateo I’s assets; +• +enter into hedging agreements; +• +declare or pay dividends, distributions or redemptions; +• +merge or consolidate; +• +make any loans or investments; +• +engage in transactions with affiliates; +• +engage in certain asset dispositions, including a sale of all or substantially all of San Mateo I’s assets; and +• +issue equity interests in San Mateo I or its subsidiaries. +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 7 — DEBT — Continued +• +failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• +failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• +bankruptcy or insolvency events involving San Mateo I or its subsidiaries; and +• +a change of control, as defined in the San Mateo Credit Facility. +The Company believes that San Mateo I was in compliance with the terms of the San Mateo Credit Facility at December 31, 2019 . +Senior Unsecured Notes +On April 14, 2015, Matador issued $ 400.0 million of 6.875 % senior notes due 2023 (the “Original 2023 Notes”) in a private placement at par value. The Original 2023 Notes were later exchanged for a like principal amount of 6.875 % senior notes due 2023 (the “2023 Exchange Notes”) that were registered under the Securities Act of 1933, as amended (the “Securities Act”), at par value. On December 9, 2016, Matador issued $ 175.0 million of 6.875 % senior notes due 2023 (the “Additional 2023 Notes”) in a private placement, at 105.5 % of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5 % . The Company received net proceeds of approximately $ 181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional 2023 Notes. The Additional 2023 Notes were later exchanged for a like principal amount of 6.875 % senior notes due 2023 that were registered under the Securities Act (together with the 2023 Exchange Notes, the “2023 Notes”). +On August 21, 2018, the Company issued $ 750.0 million of 5.875 % senior notes due 2026 (the “Original 2026 Notes”) in a private placement at par value (the “2026 Notes Offering”). The Company received net proceeds of approximately $ 740.0 million , after deducting the initial purchasers’ discounts and offering expenses. In conjunction with the 2026 Notes Offering, in August and September 2018, respectively, the Company completed a tender offer to purchase for cash and subsequent redemption of all of the 2023 Notes (the “2023 Notes Tender Offer and Redemption”). The Company used a portion of the net proceeds from the 2026 Notes Offering to fund the 2023 Notes Tender Offer and Redemption. In connection with the 2023 Notes Tender Offer and Redemption, the Company incurred a loss of $ 31.2 million , including total payments of $ 30.4 million to holders of the 2023 Notes as a result of the tender premium and the required 105.156 % redemption price payable pursuant to the 2023 Notes indenture. +On October 4, 2018, the Company issued an additional $ 300.0 million of 5.875 % senior notes due 2026 (the “Additional 2026 Notes”). The Additional 2026 Notes were issued pursuant to, and are governed by, the same indenture governing the Original 2026 Notes (the “Indenture”). The Additional 2026 Notes were issued at 100.5 % of par, plus accrued interest from August 21, 2018. The Company received net proceeds from this offering of approximately $ 297.3 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest from August 21, 2018 paid by the initial purchasers of the Additional 2026 Notes. The proceeds from this offering were used to repay a portion of the outstanding borrowings under the Credit Agreement, which were incurred in connection with the BLM Acquisition. +In December 2018, the Company exchanged substantially all of the Original 2026 Notes and Additional 2026 Notes for a like principal amount of 5.875 % senior notes due 2026 that were registered under the Securities Act (the “Notes”). The terms of the Notes are substantially the same as the terms of the Original 2026 Notes and Additional 2026 Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original 2026 Notes and Additional 2026 Notes do not apply to the Notes. The Notes will mature September 15, 2026, and interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries under the Indenture or Guarantors of the Notes (see Note 17). +On or after September 15, 2021, the Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 7 — DEBT — Continued +Year +Redemption Price +2021 +104.406 % +2022 +102.938 % +2023 +101.469 % +2024 and thereafter +100.000 % +At any time prior to September 15, 2021, the Company may redeem up to 35 % of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 105.875 % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, provided that (i) at least 65 % in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by the Company and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. +In addition, at any time prior to September 15, 2021, the Company may redeem all or part of the Notes at a redemption price equal to the sum of: +(i) the principal amount thereof, plus +(ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at September 15, 2021 plus (2) any required interest payments due on such Notes through September 15, 2021, discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus +(iii) accrued and unpaid interest, if any, to the redemption date. +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• +incur additional indebtedness; +• +sell assets; +• +pay dividends or make certain investments; +• +create liens that secure indebtedness; +• +enter into transactions with affiliates; and +• +merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• +default for 30 days in the payment when due of interest on the Notes; +• +default in the payment when due of the principal of, or premium, if any, on the Notes; +• +failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers; +• +failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture; +• +failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; +• +payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 50.0 million or more; +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 7 — DEBT — Continued +• +failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 50.0 million within 60 days; +• +any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• +certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +The outstanding borrowings of $ 255.0 million at December 31, 2019 under the Credit Agreement mature on October 31, 2023. The outstanding borrowings of $ 288.0 million at December 31, 2019 under the San Mateo Credit Facility mature on December 19, 2023. The $ 1.05 billion of outstanding Notes at December 31, 2019 mature on September 15, 2026. +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 8 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2019 and 2018 is as follows (in thousands). +December 31, +2019 +2018 +Deferred tax assets +Net operating loss carryforwards +$ +119,900 +$ +116,374 +Percentage depletion carryover +1,467 +1,624 +Compensation +13,690 +10,574 +Lease liabilities +17,107 +— +Other +9,099 +7,207 +Total deferred tax assets +161,263 +135,779 +Valuation allowance on deferred tax assets +( 6,736 +) +( 6,519 +) +Total deferred tax assets, net of valuation allowance +154,527 +129,260 +Deferred tax liabilities +Unrealized gain on derivatives +— +( 12,326 +) +Property and equipment +( 151,504 +) +( 100,634 +) +Less than wholly-owned subsidiaries +( 20,604 +) +( 6,808 +) +Lease right of use assets +( 17,107 +) +— +Other +( 2,641 +) +( 2,256 +) +Total deferred tax liabilities +( 191,856 +) +( 122,024 +) +Net deferred tax (liabilities) assets +$ +( 37,329 +) +$ +7,236 +At December 31, 2019 , the Company had net operating loss carryforwards of $ 525.2 million for federal income tax purposes and $ 163.9 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024 ; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . +At December 31, 2017, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2016 and 2015. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015. Due to a variety of factors, including the Company’s significant net income in 2017 and 2018, the Company’s federal valuation allowance and a portion of the Company’s state valuation allowance were reversed at December 31, 2018 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 8 — INCOME TAXES — Continued +The current income tax provision and the deferred income tax provision for the years ended December 31, 2019, 2018 and 2017 were comprised of the following (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Current income tax (benefit) provision +Federal income tax +$ +— +$ +( 455 +) +$ +( 8,178 +) +State income tax +— +— +21 +Net current income tax benefit +$ +— +$ +( 455 +) +$ +( 8,157 +) +Deferred income tax provision (benefit) +Federal income tax +$ +29,171 +$ +( 20,457 +) +$ +— +State income tax +6,361 +13,221 +— +Net deferred income tax provision (benefit) +$ +35,532 +$ +( 7,236 +) +$ +— +Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2019, 2018 and 2017 is as follows (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Federal tax expense at statutory rate (1) +$ +33,441 +$ +61,543 +$ +45,447 +State income tax +6,141 +16,181 +368 +Permanent differences +( 4,267 +) +( 2,488 +) +( 4,740 +) +AMT credit refundable +— +455 +8,178 +Tax Cuts and Jobs Act rate change +— +— +51,525 +Change in federal valuation allowance +— +( 80,003 +) +( 101,917 +) +Change in state valuation allowance +217 +( 2,924 +) +1,139 +Net deferred income tax provision (benefit) +35,532 +( 7,236 +) +— +Net current income tax benefit +— +( 455 +) +( 8,157 +) +Total income tax provision (benefit) +$ +35,532 +$ +( 7,691 +) +$ +( 8,157 +) +__________________ +(1) +The statutory federal tax rate was 21% for the years ended December 31, 2019 and 2018 and 35% for the year ended December 31, 2017 . +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2016 . The earliest tax year open for examination for the State of Texas tax return is 2015. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2019 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act, the Company revalued its deferred tax assets and liabilities at December 31, 2017, which resulted in a $ 51.5 million tax provision. As the Company maintained a valuation allowance against its federal and state deferred tax assets at December 31, 2017, a corresponding reduction in the valuation allowance was recorded against this tax provision; therefore, there was no net impact to the Company’s consolidated statement of operations for the year ended December 31, 2017 as a result of this corporate income tax rate change. +Corporate alternative minimum taxes were also repealed under the Tax Cuts and Jobs Act; therefore, corporate alternative minimum tax carryforwards are expected to be refunded. As a result, the Company recorded $ 0.5 million and $ 8.2 million , respectively, as a current income tax benefit in its consolidated statements of operations for the years ended December 31, 2018 and 2017. +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 9 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Plan. The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. +In 2012, the Board of Directors adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2012 Incentive Plan included employees, directors, contractors or advisors of the Company. +In 2019, the Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of December 31, 2019 , the 2019 Incentive Plan provided for a maximum of 3,433,671 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2003 Plan or the 2012 Incentive Plan, but both plans will remain in place until all awards outstanding under such plans have been settled. As of February 25, 2020 , no awards remained outstanding under the 2003 Plan. +The 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Strategic Planning and Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. At December 31, 2018, all stock-based compensation awards granted since 2012 had been granted under the 2012 Incentive Plan and substantially all are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and were liability-based awards for which the fair value was remeasured at each reporting period. +During the year ended December 31, 2019, the Company began granting both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. +Stock Options +Under the 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or 10 years . The 2003 Plan and the 2012 Incentive Plan define fair market value as the closing price of Matador’s common stock on the date of grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing price of Matador’s common stock on the trading day prior to the date of grant. All option awards granted under the 2003 Plan and still outstanding as of December 31, 2019 were settled in the first quarter of 2020. +The fair value of the 65,000 , 67,500 and 75,000 stock option awards outstanding under the 2003 Plan at December 31, 2019, 2018 and 2017 , respectively, was estimated using the following weighted average assumptions. +2019 +2018 +2017 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +0.14 years +1.14 years +2.14 years +Risk-free interest rate +1.54 % +2.48 % +1.98 % +Volatility +32.38 % +37.94 % +43.60 % +Dividend yield +— % +— % +— % +Estimated forfeiture rate +— % +— % +— % +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan and the 2019 Incentive Plan were estimated using the following weighted average assumptions during the years ended December 31, 2019, 2018 and 2017 . +2019 +2018 +2017 +Stock option pricing model +Black Scholes Merton +Black Scholes Merton +Black Scholes Merton +Expected option life +4.00 years +4.00 years +4.00 years +Risk-free interest rate +1.46 % +2.51 % +1.77 % +Volatility +48.52 % +45.17 % +47.00 % +Dividend yield +— % +— % +— % +Estimated forfeiture rate +4.43 % +2.24 % +3.66 % +Weighted average fair value of stock option awards granted during the year +$ 5.04 +$ 12.64 +$ 10.49 +The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2019 under the 2003 Plan, the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2018 +3,225 +$ +23.48 +Options granted +540 +$ +14.80 +Options exercised +( 223 +) +$ +14.93 +Options forfeited +( 10 +) +$ +27.91 +Options expired +( 272 +) +$ +23.22 +Options outstanding at December 31, 2019 +3,260 +$ +22.64 +Options outstanding at +December 31, 2019 +Options exercisable at +December 31, 2019 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life +Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$9.00 +65 +0.14 +$ +9.00 +65 +$ +9.00 +$13.22 - $15.40 +933 +3.74 +$ +14.87 +395 +$ +14.97 +$20.01 - $22.70 +663 +0.20 +$ +21.94 +658 +$ +21.95 +$25.31 - $29.68 +1,599 +3.37 +$ +28.01 +897 +$ +27.66 +At December 31, 2019 , the aggregate intrinsic value was $ 3.3 million for outstanding options and $ 1.8 million for exercisable options, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2019 was 1.69 years. +The total intrinsic value of options exercised during the years ended December 31, 2019, 2018 and 2017 was $ 0.8 million , $ 7.0 million and $ 13.2 million , respectively. The tax related benefit realized from the exercise of stock options totaled $ 2.8 million , $ 5.7 million and $ 5.0 million for the years ended December 31, 2019, 2018 and 2017 , respectively. +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +At December 31, 2019 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $ 5.5 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.72 years. +The fair value of options vested during 2019 , 2018 and 2017 was $ 9.7 million , $ 11.8 million and $ 2.1 million , respectively. +Service-Based Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2018 and 2017 were service-based awards and vest over the service period, which is one to four years . Restricted stock and restricted stock units granted in 2019 were either service-based awards, which will settle in cash or equity, or performance-based restricted stock units, which vest in an amount between zero and 200 % of the target units granted based on the Company’s relative total shareholder return over the three-year period ending December 31, 2021, as compared to a designated peer group, and will be settled in stock. All restricted stock and restricted stock unit awards outstanding at December 31, 2019 were granted under the 2012 Incentive Plan and the 2019 Incentive Plan. +Equity-Based +A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2019 is presented below (in thousands, except fair value). +Restricted Stock +Restricted Stock Units +Service Based +Service Based +Performance Based +Non-vested restricted stock and +restricted stock units +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value +Shares +Weighted +average +fair +value +Non-vested at December 31, 2018 +1,356 +$ +25.87 +58 +$ +27.48 +— +$ +— +Granted +240 +$ +19.36 +100 +$ +16.06 +428 +$ +20.00 +Vested +( 674 +) +$ +23.02 +( 57 +) +$ +27.47 +— +$ +— +Forfeited +( 25 +) +$ +28.39 +( 9 +) +$ +17.31 +— +$ +— +Non-vested at December 31, 2019 +897 +$ +26.19 +92 +$ +16.06 +428 +$ +20.00 +Liability-Based +A summary of the non-vested liability-based restricted stock units as of December 31, 2019 is presented below (in thousands, except fair value). +Non-vested +restricted stock units +Shares +Non-vested at December 31, 2018 +— +Granted +687 +Vested +— +Forfeited +( 1 +) +Non-vested at December 31, 2019 +686 +At December 31, 2019 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ 37.7 million , of which $ 12.3 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +At December 31, 2019 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $ 28.3 million , of which $ 9.1 million is expected to be settled in cash, and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.80 years. +The fair value of restricted stock and restricted stock units vested during 2019 , 2018 and 2017 was $ 13.6 million , $ 13.0 million and $ 9.9 million , respectively. +Summary +During the years ended December 31, 2019, 2018 and 2017 , the total expense attributable to stock options was $ 6.4 million , $ 6.3 million and $ 7.1 million , respectively. At December 31, 2019, 2018 and 2017 , the Company recorded a decrease of $ 0.1 million to current liabilities, a decrease of $ 1.1 million to long-term liabilities and an increase of $ 0.4 million to long-term liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2019, 2018 and 2017 , respectively. During the years ended December 31, 2019, 2018 and 2017 , the total expense attributable to restricted stock and restricted stock units was $ 20.2 million , $ 15.3 million and $ 12.9 million , respectively. During the years ended December 31, 2019, 2018 and 2017 , the Company capitalized $ 5.0 million , $ 4.4 million and $ 4.1 million , respectively, related to stock-based compensation and expensed the remaining $ 21.6 million , $ 17.2 million and $ 16.7 million , respectively. +The total tax benefit recognized for all stock-based compensation was $ 5.6 million , $ 4.8 million and $ 6.8 million for the years ended December 31, 2019, 2018 and 2017 , respectively. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 10 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3 % of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $ 1.4 million , $ 1.1 million and $ 0.9 million in 2019 , 2018 and 2017 , respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $ 1.7 million , $ 1.4 million and $ 1.1 million in 2019 , 2018 and 2017 , respectively. The Company made no additional contributions in any reporting period presented. +NOTE 11 — EQUITY +Common Stock +On May 17, 2018, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $ 0.2 million , the Company received net proceeds of approximately $ 226.4 million . +On October 10, 2017 , the Company completed a public offering of 8,000,000 shares of its common stock. After deducting offering costs totaling approximately $ 0.3 million , the Company received net proceeds of approximately $ 208.4 million . +On June 1, 2017, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 120,000,000 to 160,000,000 shares. +Treasury Stock +On October 24, 2019, October 25, 2018 and November 1, 2017, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2019, 2018 and 2017, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2019 , 2018 and 2017 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2019 , the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling and fixed price for the swaps. Each contract is set to expire at varying times during 2020, 2021 and 2022. The Company had no open contracts associated with natural gas or NGL prices at December 31, 2019 . +The following is a summary of the Company’s open costless collar contracts for oil at December 31, 2019 . +Notional Quantity (Bbl or MMBtu) +Weighted Average Price Floor ($/Bbl or +$/MMBtu) +Weighted Average Price Ceiling ($/Bbl or $/MMBtu) +Fair Value of Asset (Liability) (thousands) +Commodity +Calculation Period +Oil +01/01/2020 - 12/31/2020 +7,200,000 +$ +47.69 +$ +66.62 +$ +630 +Total open costless collar contracts +$ +630 +The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2019 . +Commodity +Calculation Period +Notional Quantity (Bbl or Gal) +Fixed Price +($/Bbl or $/Gal) +Fair Value of Asset (Liability) (thousands) +Oil Basis Swaps +01/01/2020 - 12/31/2020 +9,774,000 +$ +0.61 +$ +( 2,528 +) +Oil Basis Swaps +01/01/2021 - 12/31/2021 +6,480,000 +$ +0.82 +$ +( 1,523 +) +Oil Basis Swaps +01/01/2022 - 12/31/2022 +3,600,000 +0.90 +$ +( 460 +) +Total open swap contracts +$ +( 4,511 +) +At December 31, 2019 , the Company had an aggregate net liability value for open derivative financial instruments of $ 3.9 million . +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2019 and December 31, 2018 (in thousands). +Derivative Instruments +Gross amounts recognized +Gross amounts netted in the consolidated balance sheets +Net amounts presented in the consolidated balance sheets +December 31, 2019 +Current assets +$ +442,291 +$ +( 442,291 +) +$ +— +Other assets +280,397 +( 280,397 +) +— +Current liabilities +( 444,188 +) +442,291 +( 1,897 +) +Long-term liabilities +( 282,381 +) +280,397 +( 1,984 +) +Total +$ +( 3,881 +) +$ +— +$ +( 3,881 +) +December 31, 2018 +Current assets +$ +53,136 +$ +( 3,207 +) +$ +49,929 +Current liabilities +( 3,207 +) +3,207 +— +Long-term liabilities +( 83 +) +— +( 83 +) +Total +$ +49,846 +$ +— +$ +49,846 +The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. +Year Ended December 31, +Type of Instrument +Location in Statements of Operations +2019 +2018 +2017 +Derivative Instrument +Oil +Revenues: Realized gain (loss) on derivatives +$ +9,026 +$ +3,741 +$ +( 3,657 +) +Natural Gas +Revenues: Realized gain (loss) on derivatives +456 +( 1,407 +) +( 608 +) +NGLs +Revenues: Realized loss on derivatives +— +— +( 56 +) +Realized gain (loss) on derivatives +9,482 +2,334 +( 4,321 +) +Oil +Revenues: Unrealized (loss) gain on derivatives +( 53,443 +) +65,991 +2,638 +Natural Gas +Revenues: Unrealized (loss) gain on derivatives +( 284 +) +( 906 +) +7,077 +Unrealized (loss) gain on derivatives +( 53,727 +) +65,085 +9,715 +Total +$ +( 44,245 +) +$ +67,419 +$ +5,394 +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 13 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 +Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 +Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 +Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2019 and 2018 (in thousands). +Fair Value Measurements at +December 31, 2019 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil derivatives and basis swaps +$ +— +$ +( 3,881 +) +$ +— +$ +( 3,881 +) +Total +$ +— +$ +( 3,881 +) +$ +— +$ +( 3,881 +) +Fair Value Measurements at +December 31, 2018 using +Description +Level 1 +Level 2 +Level 3 +Total +Assets (Liabilities) +Oil derivatives and basis swaps +$ +— +$ +49,562 +$ +— +$ +49,562 +Natural gas derivatives +— +284 +— +284 +Total +$ +— +$ +49,846 +$ +— +$ +49,846 +Additional disclosures related to derivative financial instruments are provided in Note 12. +Other Fair Value Measurements +At December 31, 2019 and 2018 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximate their fair values due to their short-term maturities. +At December 31, 2019 , the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2019 and 2018 , the fair value of the Notes was $ 1.06 billion and $ 968.9 million , respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 13 — FAIR VALUE MEASUREMENTS — Continued +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2019 and 2018 . +NOTE 14 — COMMITMENTS AND CONTINGENCIES +Processing, Transportation and Salt Water Disposal Commitments +Firm Commitments +From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and salt water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and, in the case of salt water, disposal. The Company paid approximately $ 28.7 million and $ 20.6 million for deliveries under these agreements during the years ended December 31, 2019 and 2018 , respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2019 , the total deficiencies required to be paid by the Company under these agreements would be approximately $ 406.8 million , in addition to the commitments described below. +Future Commitments +In late 2017, the Company entered into a fixed-fee NGL sales agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant to a certain counterparty. The Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline extension and a fractionation facility by the counterparty, which is currently expected to be completed in 2020. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company does not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven-year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. Should the pipeline extension and fractionation facility be completed on or prior to February 28, 2021, the minimum contractual obligation during the seven-year period would be approximately $ 132.3 million . +In October 2019, the Company entered into a 15-year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The agreement begins when the counterparty’s pipeline is placed in service, which is anticipated to be the third quarter of 2020. Should the pipeline be placed in service, the Company will owe the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline, and the minimum contractual obligation would be approximately $ 106.9 million . +Delaware Basin — San Mateo +In February 2017, the Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements with subsidiaries of San Mateo I. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15 -year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo I provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at December 31, 2019 was approximately $ 152.9 million . +In connection with the February 2019 formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal (collectively, the “San Mateo II Operational Agreements”). San Mateo II provides the Company with firm service under each of the San Mateo II Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the San Mateo II Operational Agreements at inception was approximately $ 363.8 million and begins in 2020. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 14 — COMMITMENTS AND CONTINGENCIES — Continued +In June 2019, a subsidiary of San Mateo II entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed in service in 2020. San Mateo II’s total commitments under this agreement are $ 80.4 million . San Mateo II paid approximately $ 40.1 million under this agreement during the year ended December 31, 2019 . As of December 31, 2019 , the remaining obligations under this agreement were $ 40.3 million , which are expected to be paid within the next year. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $ 41.7 million at December 31, 2019 , of which $ 1.2 million is related to short-term drilling rig contracts, which are not recorded on the consolidated balance sheet. +At December 31, 2019 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $ 26.9 million at December 31, 2019 . The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 15 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2019 and 2018 (in thousands). +December 31, +2019 +2018 +Accrued evaluated and unproved and unevaluated property costs +$ +72,376 +$ +86,318 +Accrued midstream properties costs +46,402 +16,808 +Accrued lease operating expenses +18,223 +12,705 +Accrued interest on debt +18,569 +22,448 +Accrued asset retirement obligations +619 +1,350 +Accrued partners’ share of joint interest charges +14,322 +17,037 +Accrued payable related to purchased natural gas +17,806 +4,442 +Other +12,378 +9,747 +Total accrued liabilities +$ +200,695 +$ +170,855 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2019, 2018 and 2017 (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Cash paid for interest expense, net of amounts capitalized +$ +75,525 +$ +29,474 +$ +32,760 +Increase in asset retirement obligations related to mineral properties +$ +2,912 +$ +2,614 +$ +4,385 +Increase (decrease) in asset retirement obligations related to midstream properties +$ +1,204 +$ +686 +$ +( 60 +) +(Decrease) increase in liabilities for oil and natural gas properties capital expenditures +$ +( 15,877 +) +$ +( 16,802 +) +$ +48,929 +Increase (decrease) in liabilities for midstream properties capital expenditures +$ +30,374 +$ +2,499 +$ +( 955 +) +Stock-based compensation expense (benefit) recognized as liability +$ +3,170 +$ +( 1,069 +) +$ +362 +Decrease in liabilities for accrued cost to issue equity +$ +— +$ +— +$ +( 343 +) +Increase in liabilities for accrued cost to issue senior notes +$ +— +$ +232 +$ +— +Transfer of inventory from (to) oil and natural gas properties +$ +1,515 +$ +409 +$ +( 374 +) +Transfer of inventory to midstream properties +$ +— +$ +— +$ +( 317 +) +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Cash +$ +40,024 +$ +64,545 +$ +96,505 +Restricted cash +25,104 +19,439 +5,977 +Total cash and restricted cash +$ +65,128 +$ +83,984 +$ +102,482 +NOTE 16 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 16 — SEGMENT INFORMATION — Continued +oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 6). +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2019 +Oil and natural gas revenues +$ +886,127 +$ +6,198 +$ +— +$ +— +$ +892,325 +Midstream services revenues +— +135,953 +— +( 76,843 +) +59,110 +Sales of purchased natural gas +4,802 +69,967 +— +— +74,769 +Lease bonus - mineral acreage +1,711 +— +— +— +1,711 +Realized gain on derivatives +9,482 +— +— +— +9,482 +Unrealized loss on derivatives +( 53,727 +) +— +— +— +( 53,727 +) +Expenses (1) +621,687 +130,612 +72,734 +( 76,843 +) +748,190 +Operating income (loss) (2) +$ +226,708 +$ +81,506 +$ +( 72,734 +) +$ +— +$ +235,480 +Total assets (3) +$ +3,360,725 +$ +647,937 +$ +61,014 +$ +— +$ +4,069,676 +Capital expenditures (4) +$ +718,712 +$ +223,612 +$ +3,701 +$ +— +$ +946,025 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $ 331.7 million and $ 16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.7 million . +(2) +Includes $ 35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +Excludes intercompany receivables and investments in subsidiaries. +(4) +Includes $ 48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2018 +Oil and natural gas revenues +$ +794,261 +$ +6,439 +$ +— +$ +— +$ +800,700 +Midstream services revenues +— +86,737 +— +( 64,817 +) +21,920 +Sales of purchased natural gas +902 +6,169 +— +— +7,071 +Lease bonus - mineral acreage +2,489 +— +— +— +2,489 +Realized gain on derivatives +2,334 +— +— +— +2,334 +Unrealized gain on derivatives +65,085 +— +— +— +65,085 +Expenses (1) +487,539 +44,098 +69,508 +( 64,817 +) +536,328 +Operating income (loss) (2) +$ +377,532 +$ +55,247 +$ +( 69,508 +) +$ +— +$ +363,271 +Total assets (3) +$ +2,910,326 +$ +439,953 +$ +105,239 +$ +— +$ +3,455,518 +Capital expenditures (4) +$ +1,335,690 +$ +166,407 +$ +2,562 +$ +— +$ +1,504,659 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $ 252.3 million and $ 10.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.4 million . +(2) +Includes $ 25.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +Excludes intercompany receivables and investments in subsidiaries. +(4) +Includes $ 656.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 80.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production +Consolidations and Eliminations +Consolidated Company +Midstream +Corporate +Year Ended December 31, 2017 +Oil and natural gas revenues +$ +525,862 +$ +2,822 +$ +— +$ +— +$ +528,684 +Midstream services revenues +— +47,037 +— +( 36,839 +) +10,198 +Realized loss on derivatives +( 4,321 +) +— +— +— +( 4,321 +) +Unrealized gain on derivatives +9,715 +— +— +— +9,715 +Expenses (1) +333,923 +23,420 +62,931 +( 36,839 +) +383,435 +Operating income (loss) (2) +$ +197,333 +$ +26,439 +$ +( 62,931 +) +$ +— +$ +160,841 +Total assets (3) +$ +1,768,393 +$ +257,871 +$ +119,426 +$ +— +$ +2,145,690 +Capital expenditures (4) +$ +753,157 +$ +114,113 +$ +5,688 +$ +— +$ +872,958 +_____________________ +(1) +Includes depletion, depreciation and amortization expenses of $ 170.5 million and $ 5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 1.7 million . +(2) +Includes $ 12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) +Excludes intercompany receivables and investments in subsidiaries. +(4) +Includes $ 54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 17 — SUBSIDIARY GUARANTORS +The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2019 , the Guarantor Subsidiaries were 100 % owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes. +The following tables present condensed consolidating financial information of Matador (as issuer of the Notes), the Non-Guarantor Subsidiaries, the Guarantor Subsidiaries and all entities on a consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. +Condensed Consolidating Balance Sheet +December 31, 2019 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +ASSETS +Intercompany receivable +$ +1,578,133 +$ +29,217 +$ +— +$ +( 1,607,350 +) +$ +— +Current assets +29 +37,933 +240,530 +— +278,492 +Net property and equipment +— +583,899 +3,115,696 +— +3,699,595 +Investment in subsidiaries +1,332,237 +— +144,697 +( 1,476,934 +) +— +Long-term assets +— +3,072 +99,049 +( 10,532 +) +91,589 +Total assets +$ +2,910,399 +$ +654,121 +$ +3,599,972 +$ +( 3,094,816 +) +$ +4,069,676 +LIABILITIES AND EQUITY +Intercompany payable +$ +— +$ +— +$ +1,607,350 +$ +( 1,607,350 +) +$ +— +Current liabilities +— +73,086 +327,595 +( 909 +) +399,772 +Senior unsecured notes payable +1,039,416 +— +— +— +1,039,416 +Other long-term liabilities +37,329 +300,540 +332,790 +( 9,623 +) +661,036 +Total equity attributable to Matador Resources Company +1,833,654 +144,697 +1,332,237 +( 1,476,934 +) +1,833,654 +Non-controlling interest in subsidiaries +— +135,798 +— +— +135,798 +Total liabilities and equity +$ +2,910,399 +$ +654,121 +$ +3,599,972 +$ +( 3,094,816 +) +$ +4,069,676 +Condensed Consolidating Balance Sheet +December 31, 2018 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +ASSETS +Intercompany receivable +$ +1,244,405 +$ +29,816 +$ +— +$ +( 1,274,221 +) +$ +— +Current assets +4,109 +34,027 +267,549 +— +305,685 +Net property and equipment +— +379,052 +2,743,812 +— +3,122,864 +Investment in subsidiaries +1,490,401 +— +95,346 +( 1,585,747 +) +— +Long-term assets +23,897 +1,479 +11,095 +( 9,502 +) +26,969 +Total assets +$ +2,762,812 +$ +444,374 +$ +3,117,802 +$ +( 2,869,470 +) +$ +3,455,518 +LIABILITIES AND EQUITY +Intercompany payable +$ +— +$ +— +$ +1,274,221 +$ +( 1,274,221 +) +$ +— +Current liabilities +22,874 +27,988 +279,884 +( 724 +) +330,022 +Senior unsecured notes payable +1,037,837 +— +— +— +1,037,837 +Other long-term liabilities +13,221 +230,263 +73,296 +( 8,778 +) +308,002 +Total equity attributable to Matador Resources Company +1,688,880 +95,346 +1,490,401 +( 1,585,747 +) +1,688,880 +Non-controlling interest in subsidiaries +— +90,777 +— +— +90,777 +Total liabilities and equity +$ +2,762,812 +$ +444,374 +$ +3,117,802 +$ +( 2,869,470 +) +$ +3,455,518 +F-43 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 17 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2019 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +209,887 +$ +848,502 +$ +( 74,719 +) +$ +983,670 +Total expenses +( 1,458 +) +128,758 +695,609 +( 74,719 +) +748,190 +Operating (loss) income +1,458 +81,129 +152,893 +— +235,480 +Net loss on asset sales and inventory impairment +— +— +( 967 +) +— +( 967 +) +Interest expense +( 64,591 +) +( 9,282 +) +— +— +( 73,873 +) +Other income (expense) +— +3 +( 2,129 +) +— +( 2,126 +) +Earnings in subsidiaries +186,442 +— +36,645 +( 223,087 +) +— +Income before income taxes +123,309 +71,850 +186,442 +( 223,087 +) +158,514 +Total income tax provision +35,532 +— +— +— +35,532 +Net income attributable to non-controlling interest in subsidiaries +— +( 35,205 +) +— +— +( 35,205 +) +Net income attributable to Matador Resources Company shareholders +$ +87,777 +$ +36,645 +$ +186,442 +$ +( 223,087 +) +$ +87,777 +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2018 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +98,665 +$ +865,725 +$ +( 64,791 +) +$ +899,599 +Total expenses +4,935 +46,236 +549,948 +( 64,791 +) +536,328 +Operating (loss) income +( 4,935 +) +52,429 +315,777 +— +363,271 +Net loss on asset sales and inventory impairment +— +— +( 196 +) +— +( 196 +) +Interest expense +( 40,994 +) +( 333 +) +— +— +( 41,327 +) +Prepayment penalty on extinguishment of debt +( 31,226 +) +— +— +— +( 31,226 +) +Other income +565 +62 +924 +— +1,551 +Earnings in subsidiaries +343,106 +— +26,601 +( 369,707 +) +— +Income before income taxes +266,516 +52,158 +343,106 +( 369,707 +) +292,073 +Total income tax benefit +( 7,691 +) +— +— +— +( 7,691 +) +Net income attributable to non-controlling interest in subsidiaries +— +( 25,557 +) +— +— +( 25,557 +) +Net income attributable to Matador Resources Company shareholders +$ +274,207 +$ +26,601 +$ +343,106 +$ +( 369,707 +) +$ +274,207 +F-44 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2019, 2018 and 2017 +NOTE 17 — SUBSIDIARY GUARANTORS — Continued +Condensed Consolidating Statement of Operations +For the Year Ended December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Total revenues +$ +— +$ +47,883 +$ +531,508 +$ +( 35,115 +) +$ +544,276 +Total expenses +5,610 +21,260 +391,680 +( 35,115 +) +383,435 +Operating (loss) income +( 5,610 +) +26,623 +139,828 +— +160,841 +Net gain on asset sales and inventory impairment +— +— +23 +— +23 +Interest expense +( 34,565 +) +— +— +— +( 34,565 +) +Other income +27 +37 +3,487 +— +3,551 +Earnings in subsidiaries +157,589 +— +14,251 +( 171,840 +) +— +Income before income taxes +117,441 +26,660 +157,589 +( 171,840 +) +129,850 +Total income tax (benefit) provision +( 8,426 +) +269 +— +— +( 8,157 +) +Net income attributable to non-controlling interest in subsidiaries +— +( 12,140 +) +— +— +( 12,140 +) +Net income attributable to Matador Resources Company shareholders +$ +125,867 +$ +14,251 +$ +157,589 +$ +( 171,840 +) +$ +125,867 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2019 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +( 427 +) +$ +106,650 +$ +445,819 +$ +— +$ +552,042 +Net cash used in investing activities +— +( 188,893 +) +( 698,455 +) +( 16,628 +) +( 903,976 +) +Net cash provided by financing activities +— +88,059 +228,391 +16,628 +333,078 +(Decrease) increase in cash and restricted cash +( 427 +) +5,816 +( 24,245 +) +— +( 18,856 +) +Cash and restricted cash at beginning of year +456 +18,840 +64,688 +— +83,984 +Cash and restricted cash at end of year +$ +29 +$ +24,656 +$ +40,443 +$ +— +$ +65,128 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2018 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +( 657,860 +) +$ +35,119 +$ +1,231,264 +$ +— +$ +608,523 +Net cash used in investing activities +— +( 162,147 +) +( 1,310,776 +) +( 42,330 +) +( 1,515,253 +) +Net cash provided by financing activities +658,030 +140,205 +47,667 +42,330 +888,232 +Increase (decrease) in cash and restricted cash +170 +13,177 +( 31,845 +) +— +( 18,498 +) +Cash and restricted cash at beginning of year +286 +5,663 +96,533 +— +102,482 +Cash and restricted cash at end of year +$ +456 +$ +18,840 +$ +64,688 +$ +— +$ +83,984 +Condensed Consolidating Statement of Cash Flows +For the Year Ended December 31, 2017 +Matador +Non-Guarantor Subsidiaries +Guarantor Subsidiaries +Eliminating Entries +Consolidated +Net cash (used in) provided by operating activities +$ +( 307,982 +) +$ +21,308 +$ +585,799 +$ +— +$ +299,125 +Net cash provided by (used in) investing activities +33 +( 114,852 +) +( 597,870 +) +( 106,595 +) +( 819,284 +) +Net cash provided by (used in) financing activities +208,440 +96,307 +( 2,843 +) +106,595 +408,499 +Decrease (increase) in cash and restricted cash +( 99,509 +) +2,763 +( 14,914 +) +— +( 111,660 +) +Cash and restricted cash at beginning of year +99,795 +2,900 +111,447 +— +214,142 +Cash and restricted cash at end of year +$ +286 +$ +5,663 +$ +96,533 +$ +— +$ +102,482 +F-45 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2019, 2018 and 2017 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2019, 2018 and 2017 (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Property acquisition costs +Proved +$ +3,767 +$ +4,788 +$ +45,270 +Unproved and unevaluated +39,595 +633,502 +214,662 +Exploration costs +109,439 +229,974 +167,213 +Development costs +570,290 +467,426 +326,012 +Total costs incurred (1) +$ +723,091 +$ +1,335,690 +$ +753,157 +__________________ +(1) +Excludes midstream-related development and corporate costs of approximately $227.3 million, $169.0 million and $119.8 million for the years ended December 31, 2019, 2018 and 2017 , respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2019, 2018 and 2017 , most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the years ended December 31, 2019 , 2018 and 2017 , the Company capitalized $2.9 million , $17.7 million and $1.8 million, respectively, of geological and geophysical costs, which are included as exploration costs in the table above. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $4.3 million , $4.0 million and $4.8 million for the years ended December 31, 2019, 2018 and 2017 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $31.1 million , $29.9 million and $23.1 million of these internal costs for the years ended December 31, 2019 , 2018 and 2017 , respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $7.6 million , $8.8 million and $7.3 million of its interest expense for the years ended December 31, 2019 , 2018 and 2017 , respectively. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +F-46 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2019, 2018 and 2017 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2019, 2018 and 2017 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2019 , these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. For the period from January through December 2018 , these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +F-47 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2019, 2018 and 2017 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Net Proved Reserves +Oil +Natural Gas +Oil +Equivalent +(MBbl) +(MMcf) +(MBOE) +Total at December 31, 2016 +56,977 +292,649 +105,752 +Revisions of prior estimates +3,847 +34,395 +9,580 +Purchases of minerals in-place +5,257 +7,348 +6,482 +Extensions and discoveries +28,513 +99,935 +45,169 +Production +(7,851 +) +(38,163 +) +(14,212 +) +Total at December 31, 2017 +86,743 +396,164 +152,771 +Revisions of prior estimates +5,908 +32,497 +11,326 +Purchases of minerals-in-place +446 +900 +596 +Extensions and discoveries +41,445 +169,224 +69,646 +Production +(11,141 +) +(47,311 +) +(19,026 +) +Total at December 31, 2018 +123,401 +551,474 +215,313 +Revisions of prior estimates +(605 +) +34,062 +5,073 +Net divestitures of minerals-in-place +(298 +) +(12,048 +) +(2,307 +) +Extensions and discoveries +39,477 +114,833 +58,616 +Production +(13,984 +) +(61,083 +) +(24,164 +) +Total at December 31, 2019 +147,991 +627,238 +252,531 +Proved Developed Reserves +December 31, 2016 +22,604 +126,759 +43,731 +December 31, 2017 +36,966 +190,109 +68,651 +December 31, 2018 +53,223 +246,229 +94,261 +December 31, 2019 +59,667 +276,258 +105,710 +Proved Undeveloped Reserves +December 31, 2016 +34,373 +165,890 +62,021 +December 31, 2017 +49,777 +206,055 +84,120 +December 31, 2018 +70,178 +305,245 +121,052 +December 31, 2019 +88,324 +350,980 +146,821 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2019, 2018 and 2017 . +The Company’s proved oil and natural gas reserves increased to 252,531 MBOE at December 31, 2019 from 215,313 MBOE at December 31, 2018 . The Company’s proved oil and natural gas reserves increased by 61,382 MBOE and the Company produced 24,164 MBOE during the year ended December 31, 2019 , resulting in a net increase of 37,218 MBOE. The Company’s proved oil and natural gas reserves increased by 58,616 MBOE during 2019 as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 5,073 MBOE during 2019 as a result of revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells, but which were offset by lower weighted average oil and natural gas prices used to estimate proved reserves in 2019 , as compared to 2018 . The Company’s proved oil and natural gas reserves decreased by 2,307 MBOE in 2019 as a result of net divestitures of minerals-in-place primarily in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. The Company’s proved developed oil and natural gas reserves increased to 105,710 MBOE at December 31, 2019 from 94,261 MBOE at December 31, 2018 , primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2019 , the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 42% proved developed and approximately 58% proved undeveloped. +F-48 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2019, 2018 and 2017 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s proved oil and natural gas reserves increased to 215,313 MBOE at December 31, 2018 from 152,771 MBOE at December 31, 2017. The Company’s proved oil and natural gas reserves increased by 81,568 MBOE and the Company produced 19,026 MBOE during the year ended December 31, 2018, resulting in a net increase of 62,542 MBOE. The Company’s proved oil and natural gas reserves increased by 69,646 MBOE as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 11,326 MBOE during 2018 as a result of revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves in 2018, as compared to 2017. The Company also added 596 MBOE in proved oil and natural gas reserves in 2018 as a result of purchases of minerals-in-place in the Delaware Basin. The Company’s proved developed oil and natural gas reserves increased to 94,261 MBOE at December 31, 2018 from 68,651 MBOE at December 31, 2017, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2018, the Company’s proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 44% proved developed and approximately 56% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 152,771 MBOE at December 31, 2017 from 105,752 MBOE at December 31, 2016. The Company’s proved oil and natural gas reserves increased by 61,231 MBOE and the Company produced 14,212 MBOE during the year ended December 31, 2017, resulting in a net increase of 47,019 MBOE. The Company’s proved oil and natural gas reserves increased by 45,169 MBOE as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 9,580 MBOE during 2017 as a result of revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves in 2017, as compared to 2016. The Company also added 6,482 MBOE in proved oil and natural gas reserves in 2017 as a result of purchases of minerals-in-place in the Delaware Basin. The Company’s proved developed oil and natural gas reserves increased to 68,651 MBOE at December 31, 2017 from 43,731 MBOE at December 31, 2016, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2017, the Company’s proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 45% proved developed and approximately 55% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2019 , the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. For the period from January through December 2018 , the comparable average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. For the period from January through December 2017 , the comparable average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-49 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2019, 2018 and 2017 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2019, 2018 and 2017 (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Future cash inflows +$ +8,771,595 +$ +8,822,004 +$ +5,249,116 +Future production costs +(3,087,142 +) +(2,713,043 +) +(1,759,495 +) +Future development costs +(1,638,744 +) +(1,384,916 +) +(1,029,105 +) +Future income tax expense +(479,011 +) +(710,222 +) +(228,622 +) +Future net cash flows +3,566,698 +4,013,823 +2,231,894 +10% annual discount for estimated timing of cash flows +(1,532,715 +) +(1,763,210 +) +(973,248 +) +Standardized measure of discounted future net cash flows +$ +2,033,983 +$ +2,250,613 +$ +1,258,646 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2019, 2018 and 2017 (in thousands). +Year Ended December 31, +2019 +2018 +2017 +Balance, beginning of period +$ +2,250,613 +$ +1,258,646 +$ +575,043 +Net change in sales and transfer prices and in production (lifting) costs related to future production +(622,710 +) +574,381 +374,370 +Changes in estimated future development costs +(284,748 +) +(347,038 +) +(298,504 +) +Sales and transfers of oil and natural gas produced during the period +(682,747 +) +(631,596 +) +(403,095 +) +Net (divestitures) purchases of reserves in place +(28,849 +) +9,227 +97,225 +Net change due to extensions and discoveries +733,208 +1,078,935 +677,681 +Net change due to revisions in estimates of reserves quantities +63,436 +175,440 +143,749 +Previously estimated development costs incurred during the period +258,593 +279,799 +151,974 +Accretion of discount +237,548 +103,085 +54,623 +Other +(4,861 +) +3,600 +(3,929 +) +Net change in income taxes +114,500 +(253,866 +) +(110,491 +) +Standardized measure of discounted future net cash flows +$ +2,033,983 +$ +2,250,613 +$ +1,258,646 +F-50 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2019, 2018 and 2017 +SELECTED QUARTERLY FINANCIAL INFORMATION +The following table presents selected unaudited quarterly financial information for 2019 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2019 +Oil and natural gas revenues +$ +258,619 +$ +229,377 +$ +211,060 +$ +193,269 +Third-party midstream services revenues +17,656 +15,257 +14,359 +11,838 +Sales of purchased gas +34,711 +19,864 +8,963 +11,231 +Lease bonus - mineral acreage +— +1,711 +— +— +Realized gain on derivatives +1,701 +3,346 +1,165 +3,270 +Unrealized (loss) gain on derivatives +(24,012 +) +9,847 +6,157 +(45,719 +) +Expenses +223,627 +193,300 +164,915 +166,348 +Other expense +(21,209 +) +(18,859 +) +(18,859 +) +(18,039 +) +Income (loss) before income taxes +43,839 +67,243 +57,930 +(10,498 +) +Income tax provision (benefit) +10,197 +13,490 +12,858 +(1,013 +) +Net income (loss) +33,642 +53,753 +45,072 +(9,485 +) +Net income attributable to non-controlling interest in subsidiaries +(9,623 +) +(9,800 +) +(8,320 +) +(7,462 +) +Net income (loss) attributable to +Matador Resources Company shareholders +$ +24,019 +$ +43,953 +$ +36,752 +$ +(16,947 +) +Earnings (loss) per common share +Basic +$ +0.21 +$ +0.38 +$ +0.32 +$ +(0.15 +) +Diluted +$ +0.21 +$ +0.38 +$ +0.31 +$ +(0.15 +) +The following table presents selected unaudited quarterly financial information for 2018 (in thousands, except per share data). +December 31 +September 30 +June 30 +March 31 +2018 +Oil and natural gas revenues +$ +193,445 +$ +216,282 +$ +209,019 +$ +181,954 +Third-party midstream services revenues +8,636 +6,809 +3,407 +3,068 +Sales of purchased gas +7,071 +— +— +— +Lease bonus - mineral acreage +2,489 +— +— +— +Realized gain (loss) on derivatives +3,656 +5,424 +(2,488 +) +(4,258 +) +Unrealized gain (loss) on derivatives +74,577 +(21,337 +) +1,429 +10,416 +Expenses +141,811 +139,325 +137,374 +117,818 +Other expense +(11,666 +) +(42,738 +) +(8,356 +) +(8,438 +) +Income before income taxes +136,397 +25,115 +65,637 +64,924 +Income tax benefit +(7,691 +) +— +— +— +Net income +144,088 +25,115 +65,637 +64,924 +Net income attributable to non-controlling interest in subsidiaries +(7,375 +) +(7,321 +) +(5,831 +) +(5,030 +) +Net income attributable to +Matador Resources Company shareholders +$ +136,713 +$ +17,794 +$ +59,806 +$ +59,894 +Earnings per common share +Basic +$ +1.18 +$ +0.15 +$ +0.53 +$ +0.55 +Diluted +$ +1.17 +$ +0.15 +$ +0.53 +$ +0.55 +F-51 \ No newline at end of file diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/filing_metadata.csv b/raw/filings/0001520006/2019/0001520006-20-000037/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..f99dafe54a181e730afc5a03725bc4874f0a4d54 --- /dev/null +++ b/raw/filings/0001520006/2019/0001520006-20-000037/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2020-03-02,2019-12-31,2020-03-03T02:23:51.000Z,0001520006-20-000037,a20191231mtdr10-k.htm,10-K,18795641,1,1,https://www.sec.gov/Archives/edgar/data/1520006/000152000620000037/a20191231mtdr10-k.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000620000037/,2019,2019,1 diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/item1.txt b/raw/filings/0001520006/2019/0001520006-20-000037/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..edd7eb18cb76355333f608d9fcf687e80b93772b --- /dev/null +++ b/raw/filings/0001520006/2019/0001520006-20-000037/item1.txt @@ -0,0 +1,1295 @@ +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC (“San Mateo I”) together with San Mateo Midstream II, LLC (“San Mateo II”). For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• +focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• +identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• +continue to improve operational and cost efficiencies; +• +identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• +maintain our financial discipline; and +• +pursue opportunistic acquisitions, divestitures and joint ventures. +Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2019 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also improved the capital efficiency of our drilling and completion operations and continued to improve our leasehold and minerals position in the Delaware Basin. In addition, we concluded several important financing transactions in 2019, including an +2 +Table of Contents +increase in the borrowing base under our Credit Agreement (as defined below), two increases in the lender commitments under the San Mateo Credit Facility (as defined below) and the conversion of approximately $21.9 million of non-core assets to cash. San Mateo also achieved several important milestones in 2019, including the formation of San Mateo II, an increased natural gas gathering and processing commitment from an existing natural gas customer, significant additional acreage dedications from existing salt water disposal customers, an acreage dedication from a new oil customer and an increase in designed salt water disposal capacity. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2019 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2019 , we achieved record oil, natural gas and average daily oil equivalent production. In 2019 , we produced 14.0 million Bbl of oil, an increase of 26% , as compared to 11.1 million Bbl of oil produced in 2018 . We also produced 61.1 Bcf of natural gas, an increase of 29% from 47.3 Bcf of natural gas produced in 2018 . Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, an increase of 27% , as compared to 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, for the year ended December 31, 2018 . The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2019 , as compared to 59% for the year ended December 31, 2018 . +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2019 , our estimated total proved oil and natural gas reserves were 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, an increase of 17% from 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, at December 31, 2018 . The Standardized Measure of our total proved oil and natural gas reserves decrease d 10% from $2.25 billion at December 31, 2018 to $2.03 billion at December 31, 2019 . The PV-10 of our total proved oil and natural gas reserves decrease d 13% from $2.58 billion at December 31, 2018 to $2.25 billion at December 31, 2019 . The decreases in our Standardized Measure and PV-10 were primarily a result of lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2019 , as compared to December 31, 2018 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 20% to 148.0 million Bbl at December 31, 2019 from 123.4 million Bbl at December 31, 2018 . Our proved natural gas reserves increase d 14% to 627.2 Bcf at December 31, 2019 from 551.5 Bcf at December 31, 2018 . This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2019 . +At December 31, 2019 , proved developed reserves included 59.7 million Bbl of oil and 276.3 Bcf of natural gas, and proved undeveloped reserves included 88.3 million Bbl of oil and 351.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 42% and 59% , respectively, of our total proved oil and natural gas reserves at December 31, 2019 . Proved developed reserves and proved oil reserves comprised 44% and 57% , respectively, of our total proved oil and natural gas reserves at December 31, 2018 . +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past six years. We expect the Delaware Basin will continue to be our primary area of focus in 2020 . +3 +Table of Contents +We completed and began producing oil and natural gas from 138 gross (65.7 net) wells in the Delaware Basin in 2019 , including 76 gross (61.4 net) operated and 62 gross (4.3 net) non-operated wells. At December 31, 2019 , our total acreage position in the Delaware Basin was approximately 231,300 gross ( 128,200 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on the following asset areas: the Wolf and Jackson Trust asset areas in Loving County, Texas, the Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increase d approximately 23% to 55,599 BOE per day ( 84% of total oil equivalent production), including 35,184 Bbl of oil per day ( 92% of total oil production) and 122.5 MMcf of natural gas per day ( 73% of total natural gas production), in 2019 , as compared to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 . We expect our Delaware Basin production to increase in 2020 as we continue the delineation and development of these asset areas, as well as our new Stateline asset area in Eddy County, New Mexico, where we expect to begin production late in the third quarter of 2020. +Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2019 included: +• +in our Rustler Breaks asset area, the results from our first two operated First Bone Spring tests, including the Garrett State Com 32-24S-29E RB #111H (Garrett #111H) well and the Paul 25-24S-28E RB #111H (Paul #111H) well, demonstrating the prospectivity of this formation and the continued delineation and development of previously tested horizons; +• +in our Wolf asset area, the continuing success from several wells with longer laterals (greater than one mile) drilled and completed in the Wolfcamp A-XY interval; +• +in our Jackson Trust asset area, the continued development of the Wolfcamp A-Lower interval; +• +in our Arrowhead and Ranger asset areas, the results from our Wolfcamp A-XY completions, particularly in the Stebbins acreage block in the Arrowhead asset area, whose 24-hour initial potential (“IP”) test results and subsequent well performance demonstrate the prospectivity of the Wolfcamp formation moving north in the Delaware Basin; +• +in our Antelope Ridge asset area, the results from the Jeff Hart State Com #124H and #134H (Jeff Hart #124H and #134H) wells, our first two operated two-mile horizontal wells in the asset area, and the initiation of drilling operations on six wells in the western region of the asset area (the “Rodney Robinson” wells); +• +in our Stateline asset area, the successful approval and receipt of 14 drilling permits from the Bureau of Land Management (“BLM”) and the initiation of drilling operations there in late December 2019; +• +the transition to drilling longer laterals, whereby 29% of the operated horizontal wells we completed and turned to sales in 2019 had lateral lengths greater than one mile, as compared to 9% in 2018; +• +the continuing improvement in capital efficiency as demonstrated by our average drilling and completion costs for all operated horizontal wells completed and turned to sales of approximately $1,165 per lateral foot in 2019, a decrease of 24% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018; +• +the initial transportation of much of our Delaware Basin residue natural gas production to the Texas Gulf Coast on the newly commissioned Gulf Coast Express Pipeline Project (the “GCX Pipeline”) beginning in late September 2019; and +• +the significant progress made in our midstream operations, including (i) strong operating results in 2019, (ii) the initiation of an expansion of San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) by an additional 200 MMcf per day of designed natural gas processing inlet capacity, which is anticipated to be placed in service during the summer of 2020, (iii) the initiation of San Mateo’s plans to construct large diameter natural gas gathering lines southward from the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and northward from the Stateline asset area to connect these areas with the Black River Processing Plant, (iv) the addition of significant salt water disposal capacity in the Rustler Breaks asset area and the Greater Stebbins Area and (v) the progress made by San Mateo in increasing commitments, throughput volumes and acreage dedications from both new and existing customers. +We also concluded operations on our nine-well program in South Texas (initiated in late 2018) during the second quarter of 2019 , which included turning to sales seven gross (6.9 net) wells in the Eagle Ford formation and one gross (1.0 net) well in the Austin Chalk formation in 2019 . We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019 , although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that began producing in 2019 , including two highly productive two-mile lateral wells completed and turned to sales by an affiliate of Chesapeake Energy Corporation (“Chesapeake”) during the third quarter of 2019. +4 +Table of Contents +Financing Transactions +We concluded several important financing transactions in 2019 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• +the amendment of our third amended and restated credit agreement (the “Credit Agreement”) to increase the borrowing base to $900.0 million, which was further amended in February 2020 to increase our elected borrowing commitment from $500.0 million to $700.0 million; +• +the increase of the lender commitments under San Mateo I’s credit facility (the “San Mateo Credit Facility”) to $375.0 million, using the accordion feature; and +• +the conversion of approximately $21.9 million of non-core assets to cash during 2019. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. As part of this transaction, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. In addition, Five Point has committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. Five Point has also provided us the opportunity to earn deferred performance incentives of up to $150.0 million over the next several years as we execute our operational plans in and around the Greater Stebbins Area and the Stateline asset area, plus additional performance incentives for securing volumes from third-party customers. +San Mateo achieved strong operating results in 2019, highlighted by (i) increased third-party midstream services revenues, (ii) increased natural gas gathering and processing volumes, (iii) increased water gathering and water disposal volumes and (iv) increased oil gathering volumes, all as compared to 2018. San Mateo initiated construction on an additional 200 MMcf per day of designed natural gas processing inlet capacity as part of the expansion of the Black River Processing Plant, which is anticipated to be placed in service during the summer of 2020 and would bring the total designed inlet capacity of the Black River Processing Plant to 460 MMcf of natural gas per day. San Mateo also initiated plans to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. During 2019, San Mateo added four commercial salt water disposal wells, two in the Rustler Breaks asset area and two in the Greater Stebbins Area, and expects to place into service one additional commercial salt water disposal well in the Rustler Breaks asset area in the first quarter of 2020, bringing San Mateo’s designed salt water disposal capacity to approximately 335,000 Bbl per day. +During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes, obtained significant additional acreage dedications from existing salt water customers and added an acreage dedication from a new oil customer. At certain times near the end of the third quarter and early in the fourth quarter of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day. +Environmental, Social and Governance (“ESG”) Initiatives +We maintain an active ESG program and continued working in 2019 to improve upon our various ESG efforts. For instance, we significantly increased the number of our production facilities operating on electrical grid power, lowering emissions by removing on-site generators. We increased the volumes of produced water we recycled in the Delaware Basin as well as the volumes of both produced water and oil transported via pipeline, taking trucks off the roads. We also reduced the number of well pads built in 2019 through our use of batch drilling and longer laterals, reducing our surface footprint. Finally, we continued our commitment to a proactive safety culture, with over 1.4 million employee man-hours and no lost time accidents since 2017. +5 +Table of Contents +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2019 , we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2019 . +Producing +Total Identified +Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross +Net +Gross +Net +Gross +Net +% +Production +Acreage +Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +231,300 +128,200 +757 +354.0 +5,287 +2,332.4 +232,793 +39.0 +55,599 +South Texas: +Eagle Ford (5) +31,200 +28,400 +143 +121.4 +234 +196.3 +11,219 +65.5 +4,009 +Northwest Louisiana +Haynesville +17,500 +10,000 +246 +20.5 +341 +80.8 +7,652 +86.3 +6,345 +Cotton Valley (6) +16,100 +14,900 +66 +40.7 +70 +48.3 +866 +100.0 +250 +Area Total (7) +19,700 +18,300 +312 +61.2 +411 +129.1 +8,518 +87.7 +6,595 +Total +282,200 +174,900 +1,212 +536.6 +5,932 +2,657.8 +252,530 +41.9 +66,203 +__________________ +(1) +Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2019 . The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Each horizontal drilling location generally represents a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. At December 31, 2019 , these engineered drilling locations included only 372 gross (168.5 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon, Delaware and Strawn formations, in the Delaware Basin, 14 gross (13.7 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and five gross (0.5 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. Certain of these locations to which we have assigned proved undeveloped reserves may contemplate lateral lengths longer than one mile. +(2) +These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) +Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2019 . +(5) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) +Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2019 , we operated the majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2019 , we also were the operator for approximately 93% of our Eagle Ford acreage and approximately 59% of our Haynesville acreage, including approximately 26% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent +6 +Table of Contents +reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2019 , our total acreage position in Southeast New Mexico and West Texas was approximately 231,300 gross ( 128,200 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 36,400 gross (19,500 net) acres in our Ranger asset area in Lea County, 61,900 gross (26,300 net) acres in our Arrowhead asset area in Eddy County, 44,000 gross (25,000 net) acres in our Rustler Breaks asset area in Eddy County, 24,200 gross (16,500 net) acres in our Antelope Ridge asset area in Lea County, 15,000 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our Stateline asset area in Eddy County and 46,400 gross (26,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2019 . We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2019 , our acreage position in the Delaware Basin was approximately 59% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the BLM New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 73% held by existing production at December 31, 2019 . +During the year ended December 31, 2019 , we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 138 gross (65.7 net) wells in the Delaware Basin, including 76 gross (61.4 net) operated wells and 62 gross (4.3 net) non-operated wells, throughout our various asset areas. At December 31, 2019 , we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, the Avalon, the First Bone Spring, two benches of the Second Bone Spring, the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2019 . Our average daily oil equivalent production from the Delaware Basin increase d approximately 23% to 55,599 BOE per day ( 84% of total oil equivalent production), including 35,184 Bbl of oil per day ( 92% of total oil production) and 122.5 MMcf of natural gas per day ( 73% of total natural gas production), in 2019 , as compared to 45,237 BOE per day ( 87% of total oil equivalent production), including 28,026 Bbl of oil per day ( 92% of total oil production) and 103.3 MMcf of natural gas per day ( 80% of total natural gas production), in 2018 . Our average daily oil equivalent production from the Delaware Basin also grew approximately 25% from 49,309 BOE per day in the fourth quarter of 2018 to 61,493 BOE per day in the fourth quarter of 2019 . +At December 31, 2019 , approximately 92% of our estimated total proved oil and natural gas reserves, or 232.8 million BOE, was attributable to the Delaware Basin, including approximately 139.6 million Bbl of oil and 559.2 Bcf of natural gas, a 22% increase, as compared to 191.5 million BOE for the year ended December 31, 2018 . Our Delaware Basin proved reserves +7 +Table of Contents +at December 31, 2019 comprised approximately 94% of our proved oil reserves and 89% of our proved natural gas reserves, as compared to approximately 93% of our proved oil reserves and 83% of our proved natural gas reserves at December 31, 2018 . +At December 31, 2019 , we had identified 5,287 gross ( 2,332.4 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations and the deeper Strawn formation. These locations include 3,290 gross (2,139.7 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Each horizontal drilling location generally represents a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2019 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2019 , the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2019 , these potential future drilling locations included 372 gross (168.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon, Delaware and Strawn formations, to which we have assigned proved undeveloped reserves, and certain of these locations to which we have assigned proved undeveloped reserves may contemplate lateral lengths longer than one mile. +At December 31, 2019 , we were operating six drilling rigs in the Delaware Basin, and we expect to operate six rigs in the Delaware Basin throughout 2020 , including two to four rigs (at times) in the Stateline asset area, one to two rigs (at times) in the Rustler Breaks asset area, one to two rigs (at times) in the Antelope Ridge asset area, one rig in the Wolf and Jackson Trust asset areas and one rig in the Greater Stebbins Area in the southern Arrowhead asset area. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 19 months. The other three rigs are on short-term contracts with remaining obligations of less than twelve months. This affords us the ability to modify our drilling program as we may deem necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2020 . +Rustler Breaks Asset Area - Eddy County, New Mexico +We operated one to two drilling rigs in our Rustler Breaks asset area during most of 2019 . We completed and turned to sales 48 gross (16.7 net) horizontal wells and one gross (1.0 net) vertical well in the Rustler Breaks asset area in 2019, including 19 gross (14.4 net) operated and 30 gross (3.3 net) non-operated wells. +The Garrett #111H well was particularly significant, being our first operated test of the First Bone Spring formation in the Rustler Breaks asset area. This well, a one-mile lateral, tested 2,042 BOE per day (75% oil) during a 24-hour IP test in the third quarter of 2019. A second operated test of the First Bone Spring in the fourth quarter of 2019, the Paul #111H, tested 1,793 BOE per day (81% oil) during a 24-hour IP test. We believe these two wells demonstrate the prospectivity of the First Bone Spring formation in the Rustler Breaks asset area. +We were also pleased with the results from our Wolfcamp wells turned to sales in 2019 in the Rustler Breaks asset area. In particular, the General Kehoe wells in the eastern portion of the asset area were drilled and completed as part of a five-well batch from a single pad and contributed significantly to our better-than-expected oil and natural gas production in the second half of 2019. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY and Wolfcamp A-Lower formations in 2019. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2019, and we completed and turned to sales 11 gross (7.8 net) horizontal wells in these asset areas, including ten gross (7.8 net) operated wells and one gross (less than 0.1 net) non-operated well. Most of these wells were completed in the Wolfcamp A-XY interval. +We continued to experience success with longer laterals (greater than one mile) we drilled in the Wolf asset area in 2019. For example, the Howard Posner 83-TTT-B33 WF #203H and #204H (Howard Posner #203H and #204H) wells, both Wolfcamp A-XY completions, tested 2,382 BOE per day (58% oil) and 1,813 BOE per day (60% oil), respectively, during 24-hour IP tests. Both the Howard Posner #203H and #204H wells had completed lateral lengths of approximately 7,500 feet. +8 +Table of Contents +Arrowhead, Ranger and Twin Lakes Asset Areas - Eddy and Lea Counties, New Mexico +We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2019. We completed and turned to sales 20 gross (11.3 net) horizontal wells and two gross (2.0 net) vertical wells in the Arrowhead, Ranger and Twin Lakes asset areas in 2019, including 17 gross (13.0 net) operated and five gross (0.3 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals. +Following our initial test of the Wolfcamp A-XY in the third quarter of 2018, we were pleased with our continued delineation of the Wolfcamp A-XY in the Arrowhead asset area in 2019. In the third quarter of 2019, we completed and placed on production the Stebbins 19 Federal Com #203H and #204H wells. These wells tested 2,815 BOE per day (73% oil) and 2,262 BOE per day (75% oil), respectively, during 24-hour IP tests. We believe these results provided further evidence of Wolfcamp A-XY prospectivity moving north in the Delaware Basin. +Antelope Ridge Asset Area - Lea County, New Mexico +We operated one to two drilling rigs in our Antelope Ridge asset area during 2019 . We completed and turned to sales 55 gross (25.9 net) horizontal wells and one gross (1.0 net) vertical well in this asset area in 2019 , including 30 gross (26.2 net) operated and 26 gross (0.7 net) non-operated wells. As we continued to delineate the Antelope Ridge asset area during 2019, we tested six different intervals, completing wells in the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower. +A key achievement in our Antelope Ridge asset area in 2019 was the drilling and completion of our first two operated two-mile horizontal wells in the asset area—the Jeff Hart #124H and #134H wells, Second Bone Spring and Third Bone Spring completions, respectively. The Jeff Hart #124H and #134H wells tested 2,332 BOE per day (81% oil) and 2,884 BOE per day (90% oil), respectively, during 24-hour IP tests in the third quarter of 2019. The Jeff Hart #134H well produced approximately 70,000 Bbl of oil in its first 30 days of production, which is the highest 30-day cumulative oil production for any well drilled and completed by us, including our prolific Mallon wells in the Ranger asset area, also Third Bone Spring completions. Further, drilling and completion costs on the Jeff Hart #134H well were just under $1,000 per lateral foot, about 20% to 25% below the drilling and completion costs per lateral foot associated with one-mile laterals we previously drilled in the Antelope Ridge asset area. In their first five months of production, the Jeff Hart #124H and #134H wells each produced more than 200,000 Bbl of oil in its first 150 days of production. The early production from these wells has more than doubled that of our nearby one-mile lateral completions over a similar timeframe, and these wells continued to exhibit a shallower initial production decline as compared to nearby one-mile laterals drilled by us. +In addition, we were particularly pleased with our delineation of the Wolfcamp A formation in the Antelope Ridge asset area. The Brad Lummis Com #212H well, a Wolfcamp A-XY completion, flowed at 3,236 BOE per day (83% oil) during its 24-hour IP test, or over 700 BOE per 1,000 feet of completed lateral. This well result complemented those from the four Charles Ling wells completed and turned to sales in the Wolfcamp A-Lower formation late in the first quarter of 2019, which flowed at an average of 2,932 BOE per day (75% oil) during their respective 24-hour IP tests. +Additionally, we began drilling operations on the 1,200 gross and net acre Rodney Robinson tract in our western Antelope Ridge asset area in the third quarter of 2019. The Rodney Robinson tract is one of the key tracts we acquired in the BLM Acquisition. The acquired leases are federal leases and provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. We drilled six initial wells on this tract from two separate three-well pads. These six wells, which are all two-mile laterals, are currently scheduled to be completed and turned to sales in late March 2020. +9 +Table of Contents +Stateline Asset Area - Eddy County, New Mexico +In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net undeveloped leasehold acres prospective for multiple geologic targets. The acquired leases are federal leases and provide an 87.5% NRI. The large majority of the acquired acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We began drilling operations in the Stateline asset area just before the end of 2019 and, at February 25, 2020, had two of our drilling rigs operating there. We plan to develop this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.5-mile laterals on the western side of the leasehold. We initially expect to drill 13 wells on the eastern portion of this leasehold, and these 13 wells are expected to be completed and turned to sales late in third quarter of 2020 in conjunction with the expected completion of the expansion of the Black River Processing Plant by San Mateo. We anticipate running at least two rigs full-time in the Stateline asset area for the foreseeable future. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2019 , our properties included approximately 31,200 gross ( 28,400 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 93% of our Eagle Ford acreage was held by production at December 31, 2019 . +In October 2018, we commenced a drilling program in South Texas to drill nine wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and hold by production almost all of our remaining undeveloped acreage in South Texas. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight gross (7.9 net) wells, including one well drilled in the Austin Chalk formation, were completed and turned to sales in the first half of 2019. +Two of these wells, the Lloyd Hurt C #12H and D #13H wells, which targeted the Eagle Ford shale, flowed an average of 1,085 BOE per day (85% oil), including 923 Bbl of oil per day and 1.0 MMcf of natural gas per day, during 24-hour IP tests from completed lateral lengths of approximately 8,800 feet. These wells marked the two best 24-hour IP test results from any Eagle Ford wells we have completed to date in our far northwest La Salle County acreage. In addition, the Lloyd Hurt AC-C #26H well, an Austin Chalk completion, tested approximately 600 BOE per day (93% oil) during a 24-hour IP test conducted following the installation of an electric submersible pump (“ESP”) in the wellbore. We were encouraged by this initial test and the early results from the Austin Chalk formation in far northwest La Salle County, where almost no horizontal completions of the Austin Chalk formation using modern drilling and stimulation technology had been previously attempted. +Primarily as a result of the initial production from this nine-well program, our average daily oil equivalent production from the Eagle Ford shale increase d 27% to 4,009 BOE per day, including 3,113 Bbl of oil per day and 5.4 MMcf of natural gas per day, during 2019 , as compared to 3,158 BOE per day, including 2,485 Bbl of oil per day and 4.0 MMcf of natural gas per day, during 2018 . For the year ended December 31, 2019 , 6% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 6% for the year ended December 31, 2018 . +At December 31, 2019 , approximately 4% of our estimated total proved oil and natural gas reserves, or 11.2 million BOE, was attributable to the Eagle Ford shale, including approximately 8.4 million Bbl of oil and 17.2 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 6% of our proved oil reserves and 3% of our proved natural gas reserves at December 31, 2019 , as compared to approximately 7% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2018 . +At December 31, 2019 , we had identified 234 gross ( 196.3 net) engineered locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by +10 +Table of Contents +regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2019 , these 234 gross ( 196.3 net) identified drilling locations included 14 gross (13.7 net) locations to which we have assigned proved undeveloped reserves. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2019 , we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the potential prospectivity of these intervals. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019 , although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that were turned to sales in 2019 , the most significant of which were two gross (1.0 net) two-mile lateral wells drilled and completed by Chesapeake in the third quarter of 2019. These two wells, the LDW&F 15&10-14-12 HC001-ALT and HC002-ALT wells, were located in the southern part of our Elm Grove asset area in the core of the Haynesville shale play and tested 38.4 and 42.4 MMcf of natural gas per day, respectively, during 24-hour IP tests, and these wells contributed to our natural gas production growth in the second half of 2019. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2020 . +At December 31, 2019 , we held approximately 19,700 gross ( 18,300 net) acres in Northwest Louisiana, including 17,500 gross ( 10,000 net) acres in the Haynesville shale play and 16,100 gross ( 14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 26% of the 12,400 gross ( 5,600 net) acres that we consider to be in the core area of the Haynesville shale play. +For the year ended December 31, 2019 , approximately 10% of our average daily oil equivalent production, or 6,595 BOE per day, including 15 Bbl of oil per day and 39.5 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana. Natural gas production from these properties comprised approximately 24% of our daily natural gas production during 2019 , as compared to approximately 17% of our daily natural gas production during 2018 . During the year ended December 31, 2018 , approximately 7% of our average daily oil equivalent production, or 3,733 BOE per day, including 13 Bbl of oil per day and 22.3 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. +For the year ended December 31, 2019 , approximately 23% of our daily natural gas production, or 38.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1% , or 1.4 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2018 , approximately 16% of our daily natural gas production, or 20.5 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1% , or 1.8 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2019 , approximately 3% of our estimated total proved reserves, or 7.7 million BOE, was attributable to the Haynesville shale with another 0.3% of our proved reserves, or 0.9 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. +At December 31, 2019 , we had identified 341 gross ( 80.8 net) engineered locations for potential future drilling in the Haynesville shale play and 70 gross ( 48.3 net) engineered locations for potential future drilling in the Cotton Valley formation. Each horizontal drilling location generally assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into +11 +Table of Contents +account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 341 gross ( 80.8 net) locations identified for future drilling on our Haynesville acreage, 277 gross (37.8 net) locations have been identified within the 12,400 gross ( 5,600 net) acres that we believe are located in the core area of the Haynesville shale play. As we explore and develop our Northwest Louisiana acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2019 , these potential future drilling locations included 5 gross (0.5 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo I, a strategic joint venture with a subsidiary of Five Point. The midstream assets that were contributed to San Mateo I included (i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and salt water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo I and had the potential to earn up to $73.5 million in performance incentives over a five-year period. At February 28, 2020, we had received $44.1 million of the potential $73.5 million in performance incentives. We may earn up to the remaining $29.4 million in San Mateo I performance incentives over the next two years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo I. The Company and Five Point own 51% and 49% of San Mateo I, respectively. San Mateo I continues to provide firm service to us, while also being a midstream service provider to other customers in and around our Wolf and Rustler Breaks asset areas. +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. In addition, Five Point has committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. We have the ability to earn up to $150.0 million in deferred performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. +In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. San Mateo II provides firm service to us in the Greater Stebbins Area and the Stateline asset area. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During 2019, as part of the San Mateo II expansion, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. This expansion is anticipated to be placed in service during the summer of 2020. In addition, San Mateo initiated plans in 2019 to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. The expanded Black River Processing Plant supports our exploration and production development activities in the Delaware Basin and offers processing opportunities for other producers’ development efforts. +During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes. At certain times near the end of the third quarter and early in the fourth quarter +12 +Table of Contents +of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day. +In October 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including us, at December 31, 2019 , San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant. +In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs and (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connected our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo I in February 2017. +At December 31, 2019 , San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2019 , San Mateo gathered approximately 77.2 Bcf of natural gas, as compared to 46.1 Bcf of natural gas gathered during the year ended December 31, 2018 . In addition, during the year ended December 31, 2019 , San Mateo processed approximately 64.7 Bcf of natural gas at the Black River Processing Plant, as compared to 32.3 Bcf of natural gas processed during the year ended December 31, 2018 . +Crude Oil Gathering and Transportation Assets +Subsidiaries of San Mateo and Plains All American Pipeline, L.P. (“Plains”) have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +San Mateo completed its expanded oil gathering system in the Wolf asset area in Loving County, Texas (the “Wolf Oil Pipeline System”) in May 2018 and placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) in December 2018. With the Wolf Oil Pipeline System and the Rustler Breaks Oil Pipeline System (collectively, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2019 , we estimated we had on pipe almost all of our oil production from the Wolf and Rustler Breaks asset areas, which comprised approximately 56% of our Delaware Basin oil production in 2019. With the San Mateo Oil Pipeline Systems in service, we improved our oil price realizations in the Wolf and Rustler Breaks asset areas through the elimination of higher priced trucking services. +At December 31, 2019 , the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from origin points in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains Pipeline, L.P. and two trucking facilities. During the year ended December 31, 2019 , the San Mateo Oil Pipeline Systems had throughput of approximately 8.9 million Bbl of oil, as compared to 2.0 million Bbl of oil throughput during the year ended December 31, 2018 . +Produced Water Gathering and Disposal Assets +During 2019, San Mateo placed into service two commercial salt water disposal wells in the Rustler Breaks asset area and, at February 25, 2020 , expected to place into service one additional salt water disposal well in the Rustler Breaks asset area late in the first quarter of 2020, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to eight. In the Greater Stebbins Area, San Mateo also acquired an existing commercial salt water disposal well and facility and surface acreage and subsequently placed into service an additional commercial salt water disposal well. In addition to its eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area and its two commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 25, 2020 , San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, and San Mateo’s salt water gathering systems included salt +13 +Table of Contents +water gathering pipelines in the Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 25, 2020 , San Mateo expected to have a designed disposal capacity of approximately 335,000 Bbl of salt water per day by the end of the first quarter of 2020. +In June 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. In the first half of 2019, San Mateo obtained a significant additional acreage dedication and a salt water disposal well permit from another existing salt water disposal customer. +During the year ended December 31, 2019 , San Mateo gathered approximately 69.9 million Bbl of salt water, as compared to 44.0 million Bbl of salt water gathered during the year ended December 31, 2018 . In addition, during the year ended December 31, 2019 , San Mateo disposed of approximately 67.1 million Bbl of salt water, as compared to 47.5 million Bbl of salt water disposed of during the year ended December 31, 2018 . +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather and treat natural gas from most of our operated leases and from third parties and four non-commercial salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2019, 2018 and 2017 . +Year Ended December 31, +2019 +2018 +2017 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) +13,984 +11,141 +7,851 +Natural gas (Bcf) +61.1 +47.3 +38.2 +Total oil equivalent (MBOE) (1) +24,164 +19,026 +14,212 +Average daily production (BOE/d) (1) +66,203 +52,128 +38,936 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) +$ +54.34 +$ +57.04 +$ +49.28 +Oil, with realized derivatives (per Bbl) +$ +54.98 +$ +57.38 +$ +48.81 +Natural gas, without realized derivatives (per Mcf) +$ +2.17 +$ +3.49 +$ +3.72 +Natural gas, with realized derivatives (per Mcf) +$ +2.18 +$ +3.46 +$ +3.70 +Operating Expenses (per BOE): +Production taxes, transportation and processing +$ +3.82 +$ +4.00 +$ +4.10 +Lease operating +$ +4.85 +$ +4.89 +$ +4.74 +Plant and other midstream services operating +$ +1.52 +$ +1.29 +$ +0.92 +Depletion, depreciation and amortization +$ +14.51 +$ +13.94 +$ +12.49 +General and administrative +$ +3.31 +$ +3.64 +$ +4.65 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +12,843 +1,136 +— +5 +13,984 +Natural gas (Bcf) +44.7 +2.0 +13.9 +0.5 +61.1 +Total oil equivalent (MBOE) (3) +20,294 +1,463 +2,316 +91 +24,164 +Percentage of total annual net production +84.0 +% +6.0 +% +9.6 +% +0.4 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +35,184 +3,113 +— +15 +38,312 +Natural gas (MMcf/d) +122.5 +5.4 +38.1 +1.4 +167.4 +Total oil equivalent (BOE/d) +55,599 +4,009 +6,345 +250 +66,203 +Average Sales Prices (4) +Oil (per Bbl) +$ +53.95 +$ +58.71 +$ +— +$ +52.89 +$ +54.34 +Natural gas (per Mcf) +$ +2.11 +$ +3.45 +$ +2.16 +$ +2.17 +$ +2.17 +Total oil equivalent (per BOE) +$ +38.80 +$ +50.22 +$ +12.99 +$ +15.22 +$ +36.93 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.22 +$ +15.27 +$ +4.36 +$ +22.43 +$ +5.81 +__________________ +(1) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +10,230 +907 +— +4 +11,141 +Natural gas (Bcf) +37.7 +1.5 +7.5 +0.6 +47.3 +Total oil equivalent (MBOE) (3) +16,512 +1,152 +1,247 +115 +19,026 +Percentage of total annual net production +86.8 +% +6.0 +% +6.6 +% +0.6 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +28,026 +2,485 +— +13 +30,524 +Natural gas (MMcf/d) +103.3 +4.0 +20.5 +1.8 +129.6 +Total oil equivalent (BOE/d) +45,237 +3,158 +3,417 +316 +52,128 +Average Sales Prices (4) +Oil (per Bbl) +$ +56.12 +$ +67.4 +$ +— +$ +64.72 +$ +57.04 +Natural gas (per Mcf) +$ +3.55 +$ +5.46 +$ +2.85 +$ +2.80 +$ +3.49 +Total oil equivalent (per BOE) +$ +42.88 +$ +60.02 +$ +17.09 +$ +18.59 +$ +42.08 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +4.79 +$ +17.25 +$ +5.41 +$ +19.11 +$ +5.68 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +16 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas +South Texas +Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) +6,579 +1,268 +— +4 +7,851 +Natural gas (Bcf) +25.1 +2.0 +10.3 +0.8 +38.2 +Total oil equivalent (MBOE) (3) +10,754 +1,611 +1,714 +133 +14,212 +Percentage of total annual net production +75.7 +% +11.3 +% +12.1 +% +0.9 +% +100.0 +% +Average Net Daily Production Volumes +Oil (Bbl/d) +18,023 +3,475 +— +12 +21,510 +Natural gas (MMcf/d) +68.6 +5.6 +28.3 +2.1 +104.6 +Total oil equivalent (BOE/d) +29,463 +4,413 +4,697 +363 +38,936 +Average Sales Prices (4) +Oil (per Bbl) +$ +49.08 +$ +50.29 +$ +— +$ +45.52 +$ +49.28 +Natural gas (per Mcf) +$ +4.03 +$ +4.69 +$ +2.83 +$ +2.79 +$ +3.72 +Total oil equivalent (per BOE) +$ +39.41 +$ +45.58 +$ +16.96 +$ +17.69 +$ +37.20 +Production Costs (5) +Lease operating, transportation and processing (per BOE) +$ +5.80 +$ +10.92 +$ +4.21 +$ +16.77 +$ +6.29 +_________________ +(1) +Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) +Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Excludes impact of derivative settlements. +(5) +Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019 increase d 27% from our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 . This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, as compared to 52,128 BOE per day for the year ended December 31, 2018 . Our average daily oil production for the year ended December 31, 2019 was 38,312 Bbl of oil per day, an increase of 26% from 30,524 Bbl of oil per day for the year ended December 31, 2018 . Our average daily natural gas production for the year ended December 31, 2019 was 167.4 MMcf of natural gas per day, an increase of 29% from 129.6 MMcf of natural gas per day for the year ended December 31, 2018 . +Our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 increased 34% from our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017 . This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, as compared to 38,936 BOE per day for the year ended December 31, 2017 . Our average daily oil production for the year ended December 31, 2018 was 30,524 Bbl of oil per day, an increase of 42% from 21,510 Bbl of oil per day for the year ended December 31, 2017 . Our average daily natural gas production for the year ended December 31, 2018 was 129.6 MMcf of natural gas per day, an increase of 24% from 104.6 MMcf of natural gas per day for the year ended December 31, 2017 . +17 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2019 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 78% in all wells that we operated at December 31, 2019 . For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells +Natural Gas Wells +Total Wells +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +634 +298.6 +123 +55.4 +757 +354.0 +South Texas: +Eagle Ford (2) +139 +117.4 +4 +4.0 +143 +121.4 +Northwest Louisiana: +Haynesville +— +— +246 +20.5 +246 +20.5 +Cotton Valley (3) +1 +1.0 +65 +39.7 +66 +40.7 +Area Total +1 +1.0 +311 +60.2 +312 +61.2 +Total +774 +417.0 +438 +119.6 +1,212 +536.6 +__________________ +(1) +Includes 218 gross (56.5 net) vertical wells that were acquired in multiple transactions. +(2) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2019, 2018 and 2017 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +18 +Table of Contents +At December 31, (1) +2019 +2018 +2017 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) +147,991 +123,401 +86,743 +Natural Gas (Bcf) +627.2 +551.5 +396.2 +Total (MBOE) (3) +252,531 +215,313 +152,771 +Estimated proved developed reserves: +Oil (MBbl) +59,667 +53,223 +36,966 +Natural Gas (Bcf) +276.3 +246.2 +190.1 +Total (MBOE) (3) +105,710 +94,261 +68,651 +Percent developed +41.9 +% +43.8 +% +44.9 +% +Estimated proved undeveloped reserves: +Oil (MBbl) +88,324 +70,178 +49,777 +Natural gas (Bcf) +351.0 +305.2 +206.1 +Total (MBOE) (3) +146,821 +121,052 +84,120 +Standardized Measure (4) (in millions) +$ +2,034.0 +$ +2,250.6 +$ +1,258.6 +PV-10 (5) (in millions) +$ +2,248.2 +$ +2,579.3 +$ +1,333.4 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas, for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas and for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2019, 2018 and 2017 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2019, 2018 and 2017 were, in millions, $214.2 , $328.7 and $74.8 , respectively. +Our estimated total proved oil and natural gas reserves increase d 17% from 215.3 million BOE at December 31, 2018 to 252.5 million BOE at December 31, 2019 . We added 58.6 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2019 , approximately 2.4 times our 2019 annual production of 24.2 million BOE. Our proved oil reserves grew 20% from approximately 123.4 million Bbl at December 31, 2018 to approximately 148.0 million Bbl at December 31, 2019 . Our proved natural gas reserves increase d 14% from 551.5 Bcf at December 31, 2018 to 627.2 Bcf at December 31, 2019 . This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2019 . We realized approximately 5.1 million BOE in net upward revisions to our proved reserves during 2019 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2018 , and despite lower commodity prices used to estimate proved reserves at December 31, 2019 . Our proved reserves to production ratio at December 31, 2019 was 10.5 , a decrease of 7% from 11.3 at December 31, 2018 . +Over the past two years, our estimated total proved oil and natural gas reserves increased 65% from 152.8 million BOE at December 31, 2017 to 252.5 million Bbl at December 31, 2019 . Our proved oil reserves grew 71% from 86.7 million Bbl at December 31, 2017 to 148.0 million Bbl at December 31, 2019 . Our proved developed oil reserves increase d 61% from 37.0 million Bbl at December 31, 2017 to 59.7 million Bbl at December 31, 2019 . +19 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves decrease d 10% from $2.25 billion at December 31, 2018 to $2.03 billion at December 31, 2019 . The PV-10 of our total proved oil and natural gas reserves decrease d 13% from $2.58 billion at December 31, 2018 to $2.25 billion at December 31, 2019 . The decreases in our Standardized Measure and PV-10 are primarily a result of lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2019 , as compared to December 31, 2018 . The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2019 were $52.19 per Bbl and $2.58 per MMBtu, a decrease of 16% and 17% , respectively, as compared to average oil and natural gas prices of $62.04 per Bbl and $3.10 per MMBtu used to estimate proved reserves at December 31, 2018 . Our total proved reserves were made up of 59% oil and 41% natural gas at December 31, 2019 , as compared to 57% oil and 43% natural gas at December 31, 2018 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +Our proved developed oil and natural gas reserves increase d 12% from 94.3 million BOE at December 31, 2018 to 105.7 million BOE at December 31, 2019 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increase d 12% from 53.2 million Bbl at December 31, 2018 to 59.7 million Bbl at December 31, 2019 . Our proved developed natural gas reserves increase d 12% from 246.2 Bcf at December 31, 2018 to 276.3 Bcf at December 31, 2019 . +The following table summarizes changes in our estimated proved developed reserves at December 31, 2019 . +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2018 +94,261 +Extensions and discoveries +14,206 +Net divestitures of minerals-in-place +(736 +) +Revisions of prior estimates +(1,486 +) +Production +(24,164 +) +Conversion of proved undeveloped to proved developed +23,629 +As of December 31, 2019 +105,710 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increase d 21% from 121.1 million BOE at December 31, 2018 to 146.8 million BOE at December 31, 2019 . Our proved undeveloped oil and natural gas reserves increased from 70.2 million Bbl and 305.2 Bcf, respectively, at December 31, 2018 to 88.3 million Bbl and 351.0 Bcf, respectively, at December 31, 2019 , primarily as a result of our delineation and development operations in the Delaware Basin. +At December 31, 2019 , we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2019 within five years of booking these reserves. +20 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2019 . +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2018 +121,052 +Extensions and discoveries +44,410 +Net divestitures of minerals-in-place +(1,571 +) +Revisions of prior estimates +6,559 +Conversion of proved undeveloped to proved developed +(23,629 +) +As of December 31, 2019 +146,821 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2016, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil +Natural Gas +Total +(MBbl) +(Bcf) +(MBOE) (1) +2016 +4,705 +13.1 +6,883 +$ +94,579 +2017 +9,300 +45.0 +16,808 +211,860 +2018 +16,009 +61.7 +26,283 +356,830 +2019 +13,832 +58.8 +23,629 +318,609 +Total +43,846 +178.6 +73,603 +$ +981,878 +__________________ +(1) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2019 . +Net Proved Reserves (1) +Oil +Natural Gas +Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) +(Bcf) +(MBOE) (4) +(in millions) +(in millions) +Southeast New Mexico/West Texas: +Delaware Basin +139,595 +559.2 +232,793 +$ +1,877.1 +$ +2,074.8 +South Texas: +Eagle Ford (5) +8,350 +17.2 +11,219 +123.6 +136.6 +Northwest Louisiana +Haynesville +— +45.9 +7,652 +31.0 +34.3 +Cotton Valley (6) +46 +4.9 +867 +2.3 +2.5 +Area Total +46 +50.8 +8,519 +33.3 +36.8 +Total +147,991 +627.2 +252,531 +$ +2,034.0 +$ +2,248.2 +__________________ +(1) +Numbers in table may not total due to rounding. +(2) +Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) +PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2019 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes +21 +Table of Contents +associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2019 were approximately $ 214.2 million . +(4) +Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) +Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) +Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Executive Vice President of Reservoir Engineering and Chief Technology Officer is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 42 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2019 . +Developed Acres +Undeveloped Acres +Total Acres +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin +145,800 +75,000 +85,500 +53,200 +231,300 +128,200 +South Texas: +Eagle Ford +29,200 +26,500 +2,000 +1,900 +31,200 +28,400 +Northwest Louisiana (1) : +Haynesville +17,500 +10,000 +— +— +17,500 +10,000 +Cotton Valley +16,100 +14,900 +— +— +16,100 +14,900 +Area Total (2) +19,700 +18,300 +— +— +19,700 +18,300 +Total +194,700 +119,800 +87,500 +55,100 +282,200 +174,900 +__________________ +(1) +Developed acres include 2,800 gross and net mineral acres in Northwest Louisiana. +(2) +Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +22 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2019 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2025 and beyond totals 12,700 net acres, of which 9,900 net acres do not expire until 2028 and beyond. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2019. +Acres +Acres +Acres +Acres +Acres +Expiring 2020 +Expiring 2021 +Expiring 2022 +Expiring 2023 +Expiring 2024 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +17,000 +10,700 +26,400 +14,800 +18,600 +9,900 +4,800 +4,800 +300 +300 +South Texas: +Eagle Ford +1,600 +1,800 +400 +100 +— +— +— +— +— +— +Total +18,600 +12,500 +26,800 +14,900 +18,600 +9,900 +4,800 +4,800 +300 +300 +__________________ +(1) +Approximately 47% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our 2020 drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2019 , our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2019, 2018 and 2017 . +Year Ended December 31, +2019 +2018 +2017 +Gross +Net +Gross +Net +Gross +Net +Development Wells +Productive +147 +62.0 +118 +54.7 +72 +43.7 +Dry +— +— +— +— +— +— +Exploration Wells +Productive +25 +13.3 +35 +20.8 +33 +22.3 +Dry +— +— +— +— +— +— +Total Wells +Productive +172 +75.3 +153 +75.5 +105 +66.0 +Dry +— +— +— +— +— +— +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +23 +Table of Contents +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries (“OPEC”), weather conditions, including hurricanes in the Gulf Coast region, oil and natural gas storage levels, transportation capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil and Natural Gas Prices and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors — An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” +For the years ended December 31, 2019, 2018 and 2017 , we had two, four and four significant purchasers that accounted for approximately 67% , 60% and 60% , respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +24 +Table of Contents +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors — Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets Relating to a Particular Area Could Have a Material Impact on Our Business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as salt water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls +25 +Table of Contents +and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. See “Risk Factors — Approximately 26% of Our Leasehold and Mineral Acres in the Delaware Basin Are Located on Federal Lands, Which Are Subject to Administrative Permitting Requirements and Potential Federal Legislation, Regulation and Orders That May Limit or Restrict Oil and Natural Gas Operations on Federal Lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believed, as of February 25, 2020 , that the natural gas pipelines in our gathering systems met the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System, which is subject to FERC jurisdiction, includes approximately 17 miles of 10-inch diameter crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. We believed, as of February 25, 2020 , that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum +26 +Table of Contents +distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors — We May Incur Significant Costs and Liabilities Resulting from Compliance with Pipeline Safety Regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In January 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would start at $0.60 per MMBtu in 2020 and escalate to $3.00 per MMBtu by 2024. If passed, such a surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows” and “Risk Factors — The Tax Cuts and Jobs Act May Impact Our Ability to Fully Utilize Our Interest Expense Deductions and Net Operating Loss Carryovers to Fully Offset Our Taxable Income in Future Periods.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +27 +Table of Contents +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt water mitigates the need for salt water disposal and also provides cost savings to us. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the revision expands the scope of jurisdiction of the CWA, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. However, in June 2017, the EPA and the Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of WOTUS. Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining WOTUS under the CWA that existed prior to the rule. The second step would be a notice-and-comment rule-making in which the agencies would conduct a substantive reevaluation of the definition of WOTUS. In September 2019, the EPA finalized the first step in this process. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the +28 +Table of Contents +environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and NGLs We Produce, while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For +29 +Table of Contents +example, in October 2014, the Texas Railroad Commission (the “TRC”), adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. For example, certain candidates seeking the office of the President of the United States in 2020 have pledged to ban hydraulic fracturing. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands, which could adversely impact our operations in the Delaware Basin. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In 2019 and 2020, separate bills were introduced in the New Mexico Senate to place a moratorium on hydraulic fracturing. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays” and “Risk Factors — Approximately 26% of Our Leasehold and Mineral Acres in the Delaware Basin Are Located on Federal Lands, Which Are Subject to Administrative Permitting Requirements and Potential Federal Legislation, Regulation and Orders That May Limit or Restrict Oil and Natural Gas Operations on Federal Lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +30 +Table of Contents +We are subject to laws and regulations governing the security of hazardous materials under the Federal Homeland Security Act of 2002, as administered by the Department of Homeland Security (the “DHS”). The DHS promulgated the Chemical Facility Anti-Terrorism Standards to identify and secure chemical facilities that present the greatest security risk using a risk-based tiering structure. Due to the composition of the product it processes, the Black River Processing Plant was required to register with the DHS. We have submitted the required “Top-Screen” survey to the DHS and are awaiting its review by the DHS. We expect to continue to incur costs associated with administrative controls and enhanced physical security measures for the Black River Processing Plant if it is designated as a tiered facility by the DHS. +The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +Approximately 26% of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors — Insurance Against All Operational Risks is Not Available to Us.” +31 +Table of Contents +Office Lease +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. See Note 4 to the consolidated financial statements in this Annual Report for more details regarding our office lease. Such information is incorporated herein by reference. +Employees +At December 31, 2019 , we had 304 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. \ No newline at end of file diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/item13.txt b/raw/filings/0001520006/2019/0001520006-20-000037/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2019/0001520006-20-000037/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/item9a.txt b/raw/filings/0001520006/2019/0001520006-20-000037/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..815607bc208a95cf6dcf11eb8c6253c0c5a65584 --- /dev/null +++ b/raw/filings/0001520006/2019/0001520006-20-000037/item9a.txt @@ -0,0 +1,31 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2019 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2019 as included herein. +86 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +87 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018 , the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019 , and the related notes (collectively, the consolidated financial statements), and our report dated March 2, 2020 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +March 2, 2020 +88 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/rp_note.txt b/raw/filings/0001520006/2019/0001520006-20-000037/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2019/0001520006-20-000037/rpt_disclosure.txt b/raw/filings/0001520006/2019/0001520006-20-000037/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..990d6ab1f47ff2c0bd11cd391041b04e4b17e9a4 --- /dev/null +++ b/raw/filings/0001520006/2019/0001520006-20-000037/rpt_disclosure.txt @@ -0,0 +1,109 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed +below, during 2020 there was not, nor was there proposed as of December 31, 2020, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of +our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation +arrangements with directors and executive officers, which are described in “Executive Compensation—Compensation Discussion and Analysis” and “Director Compensation” above. +Working Interest and Overriding Royalty Interest Owners +Mr. Foran and certain of Mr. Foran’s affiliated +entities (collectively, the “Foran Entities”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest +owners, the Foran Entities are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Foran Entities are +entitled to receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2020, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners +or overriding royalty interest owners were approximately $1.9 million (the “Related Net Revenue Payments”). The Related Net Revenue Payments represent less than 1% of our total third-party net revenue payments during 2020. +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2020, our joint +interest billings to the Foran Entities attributable to their share of costs were approximately $1.8 million (the “Related Joint Interest Billings”). The Related Joint Interest Billings represent less than 1% of our total joint +interest billings during 2020. As a result of this ownership by the Foran Entities, from time to time, we will be in a net receivable or net payable position with certain of the Foran Entities. We do not consider any net receivables from the Foran +Entities to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Foran Entities for +potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s relationships and interests in such transactions and all other material facts related to the Related Net Revenue +Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments +and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Certain Employment Relationships +Billy E. Goodwin, Executive Vice President and Chief Operating +Officer—Drilling, Completions & Production, was appointed as an executive officer of the Company in connection with his February 2016 promotion to Senior Vice President—Operations. Two of Mr. Goodwin’s adult children +have been employees of the Company since 2014 and 2015, respectively, and each earned in 2020, and are expected to be compensated in 2021, between $120,000 and $500,000. One of Mr. Goodwin’s children has a Bachelor of Science degree in +Petroleum Engineering from the University of Tulsa and over 11 years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other child has a +Bachelor of Science in Business Administration degree in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He also has over 11 years of industry +experience, including as a drilling fluids engineer for a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangements for +potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangements and +2021 +Proxy Statement | Matador Resources Company 71 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +historical and anticipated compensation of Mr. Goodwin’s adult children, and all other material facts related to the relationship, determined that the employment arrangements were fair +to the Company and recommended +the employment arrangements to the full Board for approval and ratification. The Board subsequently approved and ratified such +employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s +sister-in-law has been an employee of the Company since 2016 and earned in 2020, and is expected to be compensated in 2021, between $120,000 and $200,000. +Mr. Baribault’s sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist +University Legal Assistants Program. She has over 39 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person +Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s +sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the +employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of +Mr. Foran has been an employee of the Company since 2015 and earned in 2020, and is expected to be compensated in 2021, between $120,000 and $200,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development +and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than 10 years of industry experience, including with another publicly traded exploration and production company. The Audit Committee +reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated +compensation of Mr. Foran’s adult child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval +and ratification. The Board subsequently approved and ratified such employment arrangement. +Procedures for Approval of Related Person +Transactions +Pursuant to the Related Person +Transaction Policy as in effect as of December 31, 2020, a “Related Person Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of +indebtedness)), or series of related transactions, or any material amendment to any such transaction, in which a Related Person (as defined below) has or will have a direct or indirect material interest and in which we are a participant, other than: +• +a transaction involving compensation of directors that is required to be reported in our proxy statement under Item 402 of +the SEC’s compensation disclosure requirements (“Item 402”); +• +any employment by us of an executive officer if: +o +the related compensation is required to be reported in our proxy statement under Item 402; or +o +the executive officer is not an “immediate family member” of another executive officer or director of the +Company, the related compensation would be reported in our proxy statement under Item 402 if the executive officer was a “named executive officer” and the Compensation Committee approved (or recommended that the Board approve) such +compensation; +• +a transaction with a Related Person involving less than $120,000; +• +a transaction in which the interest of the Related Person arises solely from the ownership of a class of our equity +securities and all holders of that class receive the same benefit on a pro rata basis; +• +a transaction in which a Related Person has an indirect interest solely as a result of being (a) a director or, +together with all other Related Persons, a less than 10% beneficial owner of an equity interest in another entity, or both, or (b) a limited partner in a partnership in which the Related Person, together with all other Related Persons, has an +interest of less than 10%; +72 Matador Resources Company | 2021 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that +involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority; +• +any transaction with another company at which a Related Person’s only relationship is as an employee (other than an +executive officer), if the aggregate amount involved does not exceed the greater of $1,000,000, or 2% of that company’s total annual revenues; +• +any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a +Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the lesser of $1,000,000, or 2% of the charitable organization’s total annual receipts; or +• +any transaction with another publicly traded company where the Related Person’s interest arises solely from beneficial +ownership of more than 5% of our Common Stock and ownership of a non-controlling interest in the other publicly traded company. +“Related Person” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors +or nominees for director; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, +sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law or person residing (other than a tenant or employee) in the home of a director, nominee for director, executive officer or a beneficial owner of more than 5% of +our Common Stock; and +• +any entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a +general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Person Transaction Policy, the Audit Committee must review all material facts of each Related Person Transaction and recommend either approval +or disapproval of the Related Person Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Person Transaction, the Audit Committee must, after reviewing all +material facts of the Related Person Transaction and the Related Person’s relationship and interest, determine whether the Related Person Transaction is fair to the Company. Further, the policy requires that all Related Person Transactions be +disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +2021 +Proxy Statement | Matador Resources Company 73 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/filing.txt b/raw/filings/0001520006/2020/0001520006-21-000056/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..8a406ecbdb5dcd6fbf5e53dbad133209475b50a6 --- /dev/null +++ b/raw/filings/0001520006/2020/0001520006-21-000056/filing.txt @@ -0,0 +1,3216 @@ +mtdr-20201231 +0001520006 false 2020 FY P5Y P1M us-gaap:OtherLiabilitiesCurrent us-gaap:OtherLiabilitiesCurrent us-gaap:OtherLiabilitiesNoncurrent us-gaap:OtherLiabilitiesNoncurrent us-gaap:OtherLiabilitiesCurrent us-gaap:OtherLiabilitiesNoncurrent us-gaap:OtherAssetsNoncurrent P3Y P5Y P6Y P1Y P3Y 0001520006 2020-01-01 2020-12-31 iso4217:USD 0001520006 2020-06-30 xbrli:shares 0001520006 2021-02-23 0001520006 2020-12-31 0001520006 2019-12-31 iso4217:USD xbrli:shares 0001520006 us-gaap:OilAndGasMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember 2019-01-01 2019-12-31 0001520006 us-gaap:OilAndGasMember 2018-01-01 2018-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2018-01-01 2018-12-31 0001520006 mtdr:NaturalGasSalesMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember 2018-01-01 2018-12-31 0001520006 2019-01-01 2019-12-31 0001520006 2018-01-01 2018-12-31 0001520006 us-gaap:CommonStockMember 2017-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2017-12-31 0001520006 us-gaap:RetainedEarningsMember 2017-12-31 0001520006 us-gaap:TreasuryStockMember 2017-12-31 0001520006 us-gaap:ParentMember 2017-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2017-12-31 0001520006 2017-12-31 0001520006 us-gaap:CommonStockMember 2018-01-01 2018-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2018-01-01 2018-12-31 0001520006 us-gaap:ParentMember 2018-01-01 2018-12-31 0001520006 us-gaap:TreasuryStockMember 2018-01-01 2018-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2018-01-01 2018-12-31 0001520006 us-gaap:RetainedEarningsMember 2018-01-01 2018-12-31 0001520006 us-gaap:CommonStockMember 2018-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2018-12-31 0001520006 us-gaap:RetainedEarningsMember 2018-12-31 0001520006 us-gaap:TreasuryStockMember 2018-12-31 0001520006 us-gaap:ParentMember 2018-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2018-12-31 0001520006 2018-12-31 0001520006 us-gaap:CommonStockMember 2019-01-01 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2019-01-01 2019-12-31 0001520006 us-gaap:ParentMember 2019-01-01 2019-12-31 0001520006 us-gaap:TreasuryStockMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIMember us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001520006 us-gaap:ParentMember mtdr:SanMateoIMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIIMember us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIIMember us-gaap:ParentMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIIMember us-gaap:NoncontrollingInterestMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIIMember 2019-01-01 2019-12-31 0001520006 us-gaap:RetainedEarningsMember 2019-01-01 2019-12-31 0001520006 us-gaap:CommonStockMember 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2019-12-31 0001520006 us-gaap:RetainedEarningsMember 2019-12-31 0001520006 us-gaap:TreasuryStockMember 2019-12-31 0001520006 us-gaap:ParentMember 2019-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2019-12-31 0001520006 us-gaap:CommonStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-01-01 2020-12-31 0001520006 us-gaap:ParentMember 2020-01-01 2020-12-31 0001520006 us-gaap:TreasuryStockMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIMember us-gaap:AdditionalPaidInCapitalMember 2020-01-01 2020-12-31 0001520006 us-gaap:ParentMember mtdr:SanMateoIMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIIMember us-gaap:AdditionalPaidInCapitalMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIIMember us-gaap:ParentMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIIMember us-gaap:NoncontrollingInterestMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIIMember 2020-01-01 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-01-01 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-01-01 2020-12-31 0001520006 us-gaap:CommonStockMember 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-12-31 0001520006 us-gaap:TreasuryStockMember 2020-12-31 0001520006 us-gaap:ParentMember 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-12-31 0001520006 srt:MinimumMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember 2020-01-01 2020-12-31 mtdr:Purchasers xbrli:pure 0001520006 us-gaap:RevenueFromContractWithCustomerMember 2020-01-01 2020-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2020-01-01 2020-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2020-01-01 2020-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember 2019-01-01 2019-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2019-01-01 2019-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember mtdr:BPAmericaProductionCompanyMember us-gaap:RevenueFromContractWithCustomerMember 2019-01-01 2019-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember 2018-01-01 2018-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2018-01-01 2018-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember mtdr:BPAmericaProductionCompanyMember us-gaap:RevenueFromContractWithCustomerMember 2018-01-01 2018-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember mtdr:OccidentalEnergyMarketingInc.Member 2018-01-01 2018-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember mtdr:WesternRefiningOilMember us-gaap:RevenueFromContractWithCustomerMember 2018-01-01 2018-12-31 0001520006 us-gaap:AccountsReceivableMember 2020-01-01 2020-12-31 0001520006 us-gaap:AccountsReceivableMember 2019-01-01 2019-12-31 0001520006 us-gaap:AccountsReceivableMember 2018-01-01 2018-12-31 iso4217:USD utr:bbl iso4217:USD utr:MMBTU 0001520006 us-gaap:MachineryAndEquipmentMember 2020-01-01 2020-12-31 0001520006 srt:MinimumMember us-gaap:MachineryAndEquipmentMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember us-gaap:MachineryAndEquipmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2018-01-01 2018-12-31 0001520006 srt:OilReservesMember 2020-01-01 2020-12-31 0001520006 srt:OilReservesMember 2019-01-01 2019-12-31 0001520006 srt:OilReservesMember 2018-01-01 2018-12-31 0001520006 srt:NaturalGasReservesMember 2020-01-01 2020-12-31 0001520006 srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001520006 srt:NaturalGasReservesMember 2018-01-01 2018-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2020-01-01 2020-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2019-01-01 2019-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2018-01-01 2018-12-31 0001520006 us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2020-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2019-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2020-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2019-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2020-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2019-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2020-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2019-12-31 0001520006 mtdr:CurrentYearMember 2020-12-31 0001520006 mtdr:PriorYearMember 2019-12-31 0001520006 mtdr:TwoYearsPriorMember 2018-12-31 0001520006 mtdr:ThreeYearsandPriorMember 2017-12-31 0001520006 mtdr:ProjectsInceptiontoDateMember 2020-12-31 utr:acre 0001520006 mtdr:BLMAcquisitionMember 2018-09-12 0001520006 mtdr:BLMAcquisitionMember 2018-09-12 2018-09-12 0001520006 mtdr:OperatingLeaseExpenseMember 2020-01-01 2020-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2019-01-01 2019-12-31 0001520006 us-gaap:OilAndGasServiceMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasServiceMember 2019-01-01 2019-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2020-01-01 2020-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2019-01-01 2019-12-31 0001520006 mtdr:DrillingRigLeasesMember 2020-01-01 2020-12-31 0001520006 mtdr:DrillingRigLeasesMember 2019-01-01 2019-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2020-01-01 2020-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2019-01-01 2019-12-31 mtdr:well 0001520006 mtdr:RustlerBreaksAssetAreaMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 0001520006 mtdr:WolfAssetAreaMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2017-02-17 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 2017-02-17 0001520006 us-gaap:SubsequentEventMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2021-02-23 2021-02-23 0001520006 us-gaap:SubsequentEventMember mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2017-02-17 2021-02-23 0001520006 srt:ScenarioForecastMember mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2021-01-01 2021-03-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2020-01-01 2020-12-31 0001520006 mtdr:RustlerBreaksandWolfAssetAreaMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 2017-02-17 0001520006 mtdr:RustlerBreaksAssetAreaMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 2017-02-17 0001520006 mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-02-25 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2019-02-25 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-02-25 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-02-25 2019-02-25 0001520006 mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2020-12-31 0001520006 mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2019-12-31 0001520006 mtdr:PropertyContributionMember mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-01-01 2019-03-31 0001520006 us-gaap:UnsecuredDebtMember us-gaap:SeniorNotesMember 2020-12-31 0001520006 mtdr:SBALoanCARESActMember us-gaap:UnsecuredDebtMember 2020-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2020-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2020-02-29 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2020-03-01 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2020-10-30 0001520006 us-gaap:RevolvingCreditFacilityMember 2020-10-30 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2020-12-31 0001520006 us-gaap:SubsequentEventMember 2021-01-01 2021-02-23 0001520006 mtdr:FederalFundsEffectiveRateMember mtdr:ThirdAmendedCreditAgreementMember 2020-01-01 2020-12-31 0001520006 mtdr:LiborRateMember mtdr:ThirdAmendedCreditAgreementMember 2020-01-01 2020-12-31 0001520006 mtdr:BaseRateLoanMember srt:MinimumMember 2020-01-01 2020-12-31 0001520006 mtdr:BaseRateLoanMember srt:MaximumMember mtdr:ThirdAmendedCreditAgreementMember 2020-01-01 2020-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MinimumMember us-gaap:EurodollarMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:EurodollarMember 2020-01-01 2020-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MinimumMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember mtdr:ThirdAmendedCreditAgreementMember 2020-01-01 2020-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2020-01-01 2020-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2019-10-31 0001520006 mtdr:SanMateoCreditFacilityMember 2020-12-31 0001520006 us-gaap:SubsequentEventMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2021-01-01 2021-02-23 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember us-gaap:FederalFundsEffectiveSwapRateMember 2018-12-19 2018-12-19 0001520006 mtdr:AdjustedLIBORateMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 mtdr:AdjustedLIBORateMember srt:MinimumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 mtdr:AdjustedLIBORateMember srt:MaximumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 srt:MinimumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember mtdr:StatutoryReserveRateMember 2018-12-19 2018-12-19 0001520006 srt:MaximumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember mtdr:StatutoryReserveRateMember 2018-12-19 2018-12-19 0001520006 srt:MinimumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 srt:MaximumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 mtdr:TheBankOfNovaScotiaMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember 2015-04-14 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember 2015-04-14 2015-04-14 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember 2016-12-09 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2016-12-09 2016-12-09 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember 2020-12-31 0001520006 2016-12-09 2016-12-09 0001520006 mtdr:A2026NotesOfferingMember us-gaap:UnsecuredDebtMember 2018-08-21 0001520006 mtdr:A2026NotesOfferingMember us-gaap:UnsecuredDebtMember 2018-08-21 2018-08-21 0001520006 2018-08-21 2018-08-21 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember 2018-08-21 2018-08-21 0001520006 mtdr:SeniorNotesDue2023Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2018-08-21 2018-08-21 0001520006 mtdr:Additional2026NotesMember us-gaap:UnsecuredDebtMember 2018-10-04 0001520006 mtdr:Additional2026NotesMember us-gaap:UnsecuredDebtMember 2018-10-04 2018-10-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:DebtInstrumentRedemptionPeriodTwoMember us-gaap:UnsecuredDebtMember 2018-10-04 2018-10-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodThreeMember 2018-10-04 2018-10-04 0001520006 us-gaap:DebtInstrumentRedemptionPeriodFourMember mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2018-10-04 2018-10-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:DebtInstrumentRedemptionPeriodFiveMember us-gaap:UnsecuredDebtMember 2018-10-04 2018-10-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2018-10-04 2018-10-04 0001520006 mtdr:Additional2026NotesMember us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2018-10-04 2018-10-04 0001520006 mtdr:Additional2026NotesMember us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2018-10-04 0001520006 us-gaap:InternalRevenueServiceIRSMember 2020-12-31 0001520006 us-gaap:StateAndLocalJurisdictionMember 2020-12-31 0001520006 us-gaap:CommonClassAMember 2020-01-01 2020-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2020-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2020-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2020-01-01 2020-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2019-01-01 2019-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2018-01-01 2018-12-31 0001520006 mtdr:RangeTwoMember 2020-01-01 2020-12-31 0001520006 mtdr:RangeTwoMember 2020-12-31 0001520006 mtdr:RangeThreeMember 2020-01-01 2020-12-31 0001520006 mtdr:RangeThreeMember 2020-12-31 0001520006 mtdr:RangeFourMember 2020-01-01 2020-12-31 0001520006 mtdr:RangeFourMember 2020-12-31 0001520006 us-gaap:RestrictedStockMember srt:MinimumMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 srt:MinimumMember mtdr:PerformanceBasedStockUnitsMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember mtdr:PerformanceBasedStockUnitsMember 2020-01-01 2020-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember 2020-01-01 2020-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2019-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2019-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2019-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2020-01-01 2020-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2020-01-01 2020-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2020-01-01 2020-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2019-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2020-01-01 2020-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2019-01-01 2019-12-31 0001520006 us-gaap:RestrictedStockMember 2018-01-01 2018-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2020-01-01 2020-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2019-01-01 2019-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2018-01-01 2018-12-31 0001520006 us-gaap:CommonStockMember mtdr:PublicStockOfferingMember 2018-05-17 2018-05-17 0001520006 2018-05-17 2018-05-17 0001520006 2016-03-11 2016-03-11 utr:bbl 0001520006 srt:OilReservesMember mtdr:OpenCostlessCollarContractsMember 2020-12-31 0001520006 mtdr:DerivativeContractCalculationPeriodOneMember srt:NaturalGasReservesMember mtdr:OpenCostlessCollarContractsMember 2020-12-31 0001520006 mtdr:DerivativeContractCalculationPeriodTwoMember srt:NaturalGasReservesMember mtdr:OpenCostlessCollarContractsMember 2020-12-31 0001520006 mtdr:OpenCostlessCollarContractsMember 2020-12-31 0001520006 mtdr:DerivativeContractCalculationPeriodOneMember srt:OilReservesMember mtdr:OpenSwapContractsMember 2020-12-31 0001520006 mtdr:OpenSwapContractsMember 2020-12-31 0001520006 mtdr:OpenBasisSwapContractsMember mtdr:DerivativeContractCalculationPeriodOneMember mtdr:OilBasisSwapsMember 2020-12-31 0001520006 mtdr:OpenBasisSwapContractsMember mtdr:DerivativeContractCalculationPeriodThreeMember mtdr:OilBasisSwapsMember 2020-12-31 0001520006 mtdr:OpenBasisSwapContractsMember 2020-12-31 0001520006 us-gaap:OtherCurrentAssetsMember 2020-12-31 0001520006 us-gaap:OtherNoncurrentAssetsMember 2020-12-31 0001520006 us-gaap:OtherCurrentLiabilitiesMember 2020-12-31 0001520006 us-gaap:OtherNoncurrentLiabilitiesMember 2020-12-31 0001520006 us-gaap:OtherCurrentAssetsMember 2019-12-31 0001520006 us-gaap:OtherNoncurrentAssetsMember 2019-12-31 0001520006 us-gaap:OtherCurrentLiabilitiesMember 2019-12-31 0001520006 us-gaap:OtherNoncurrentLiabilitiesMember 2019-12-31 0001520006 mtdr:RevenuesMember srt:OilReservesMember 2020-01-01 2020-12-31 0001520006 mtdr:RevenuesMember srt:OilReservesMember 2019-01-01 2019-12-31 0001520006 mtdr:RevenuesMember srt:OilReservesMember 2018-01-01 2018-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2019-01-01 2019-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2018-01-01 2018-12-31 0001520006 mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 mtdr:RevenuesMember 2019-01-01 2019-12-31 0001520006 mtdr:RevenuesMember 2018-01-01 2018-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2019-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2019-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember 2019-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2019-12-31 0001520006 us-gaap:PipelinesMember 2020-01-01 2020-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2020-01-01 2020-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2019-01-01 2019-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2020-12-31 0001520006 mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember mtdr:EddyCountyMember 2019-10-01 2019-10-31 0001520006 mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember mtdr:EddyCountyMember 2019-10-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2020-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:OperationalAgreementsMember 2019-02-25 0001520006 mtdr:EngineeringProcurementConstructionAndInstallationOfProcessingPlantMember mtdr:SanMateoMidstreamMember 2020-12-31 0001520006 mtdr:EngineeringProcurementConstructionAndInstallationOfProcessingPlantMember mtdr:SanMateoMidstreamMember 2020-01-01 2020-12-31 0001520006 mtdr:DrillingRigCommitmentsMember 2020-12-31 0001520006 srt:MinimumMember mtdr:DrillingRigCommitmentsMember 2020-01-01 2020-12-31 0001520006 srt:MaximumMember mtdr:DrillingRigCommitmentsMember 2020-01-01 2020-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2020-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2019-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2020-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2019-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2020-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2019-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2020-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2019-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2020-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2019-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2020-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2019-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2020-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2019-12-31 mtdr:segment 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember us-gaap:OilAndGasMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:NaturalGasMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember mtdr:NaturalGasSalesMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember us-gaap:OilAndGasMember 2019-01-01 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2019-01-01 2019-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:NaturalGasMidstreamMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember mtdr:NaturalGasSalesMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2019-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2019-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember us-gaap:OilAndGasMember 2018-01-01 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2018-01-01 2018-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2018-01-01 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:NaturalGasMidstreamMember 2018-01-01 2018-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2018-01-01 2018-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2018-01-01 2018-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:CorporateNonSegmentMember mtdr:NaturalGasSalesMember 2018-01-01 2018-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2018-01-01 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2018-01-01 2018-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2018-01-01 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2018-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2018-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2018-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2018-12-31 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31 , 2020 +or +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-35410 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas 27-4662601 +(State or other jurisdiction of +incorporation or organization) (I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 75240 +Dallas, Texas +(Address of principal executive offices) (Zip Code) +( 972 ) 371-5200 +(Registrant’s telephone number, including area code) +_________________________________________________________ +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Trading symbol(s) Name of each exchange on which registered +Common Stock, par value $0.01 per share MTDR New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ☒ No ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ☐ No ☒ +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $ 930,575,164 . +As of February 23, 2021, there were 116,764,838 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2021 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +33 +I TEM 1B. +Unresolved Staff Comments +63 +I TEM 2. +Properties +64 +I TEM 3. +Legal Proceedings +64 +I TEM 4. +Mine Safety Disclosures +64 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +65 +I TEM 6. +Selected Financial Data +68 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +68 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +89 +I TEM 8. +Financial Statements and Supplementary Data +90 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +90 +I TEM 9A. +Controls and Procedures +90 +I TEM 9B. +Other Information +93 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +93 +I TEM 11. +Executive Compensation +93 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +93 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +93 +I TEM 14. +Principal Accounting Fees and Services +93 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +94 +ITEM 16. +Form 10-K Summary +94 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus (“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of our midstream joint venture’s Black River cryogenic natural gas processing plant; the timing and operating results of the buildout by our midstream joint venture of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• our business strategy; +• our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized; +• our cash flows and liquidity; +• the amount, timing and payment of dividends, if any; +• our financial strategy, budget, projections and operating results; +• the supply and demand of oil, natural gas and natural gas liquids; +• oil, natural gas and natural gas liquids prices, including our realized prices thereof; +• the timing and amount of future production of oil and natural gas; +• the availability of drilling and production equipment; +• the availability of oil storage capacity; +• the availability of oil field labor; +• the amount, nature and timing of capital expenditures, including future exploration and development costs; +• the availability and terms of capital; +• our drilling of wells; +• our ability to negotiate and consummate acquisition and divestiture opportunities; +• government regulation and taxation of the oil and natural gas industry; +• our marketing of oil and natural gas; +• our exploitation projects or property acquisitions; +• the integration of acquisitions with our business; +• our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the operation of its Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; +• the ability of our midstream joint venture to attract third-party volumes; +• our costs of exploiting and developing our properties and conducting other operations; +• general economic conditions; +• competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• the effectiveness of our risk management and hedging activities; +• our technology; +• environmental liabilities; +• counterparty credit risk; +1 +Table of Contents +• developments in oil-producing and natural gas-producing countries; +• the impact of COVID-19 on the oil and natural gas industry and our business; +• our future operating results; and +• our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo I”) together with San Mateo Midstream II, LLC (collectively with its subsidiaries, “San Mateo II”). Effective October 1, 2020, San Mateo II merged with and into San Mateo I. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +2 +Table of Contents +• maintain our financial discipline; and +• pursue opportunistic acquisitions, divestitures and joint ventures. +Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, the successful execution of our business strategies led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2020. We achieved these results despite reducing our operated drilling rig count from six at the beginning of the year to three by the end of the second quarter. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”). In addition, we concluded several important financing transactions in 2020, including an increase in the elected commitment under our Credit Agreement (as defined below), the affirmation of the borrowing base and the restructuring of our oil hedging portfolio. San Mateo also achieved several important milestones in 2020, including the expansion of its cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and associated pipelines and the merger of San Mateo II with and into San Mateo I. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2020 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2020, we achieved record oil, natural gas and average daily oil equivalent production. In 2020, we produced 15.9 million Bbl of oil, an increase of 14%, as compared to 14.0 million Bbl of oil produced in 2019. We also produced 69.5 Bcf of natural gas, an increase of 14% from 61.1 Bcf of natural gas produced in 2019. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, an increase of 14%, as compared to 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, for the year ended December 31, 2019. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for both the years ended December 31, 2020 and December 31, 2019. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, an increase of 7% from 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, at December 31, 2019. The Standardized Measure of our total proved oil and natural gas reserves decreased 22% from $2.03 billion at December 31, 2019 to $1.58 billion at December 31, 2020. The PV-10 of our total proved oil and natural gas reserves decreased 26% from $2.25 billion at December 31, 2019 to $1.66 billion at December 31, 2020. The decreases in our Standardized Measure and PV-10 were primarily a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 8% to 159.9 million Bbl at December 31, 2020 from 148.0 million Bbl at December 31, 2019. Our proved natural gas reserves increased 6% to 662.3 Bcf at December 31, 2020 from 627.2 Bcf at December 31, 2019. This growth in oil and natural gas reserves was attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2020. +At December 31, 2020, proved developed reserves included 69.6 million Bbl of oil and 323.2 Bcf of natural gas, and proved undeveloped reserves included 90.3 million Bbl of oil and 339.1 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 46% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2020. Proved developed reserves and proved oil reserves comprised 42% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2019. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, +3 +Table of Contents +completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2021. +We completed and began producing oil and natural gas from 89 gross (47.8 net) wells in the Delaware Basin in 2020, including 53 gross (45.6 net) operated and 36 gross (2.2 net) non-operated wells. At December 31, 2020, our total acreage position in the Delaware Basin was approximately 230,600 gross (124,700 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on the following asset areas: the Wolf and Jackson Trust asset areas in Loving County, Texas, the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 21% to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020, as compared to 55,599 BOE per day (84% of total oil equivalent production), including 35,184 Bbl of oil per day (92% of total oil production) and 122.5 MMcf of natural gas per day (73% of total natural gas production), in 2019. We expect our Delaware Basin production to increase in 2021 as we continue the delineation and development of these asset areas. +During 2020, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) were: +• we completed and turned to sales the first six Rodney Robinson wells, all of which were two-mile laterals, in the western portion of our Antelope Ridge asset area, in late March 2020; these six Rodney Robinson wells have produced in aggregate approximately 2.7 million BOE in approximately 10 months of production; +• we completed and turned to sales the first five Ray State wells, all of which were two-mile laterals, in the eastern portion of our Rustler Breaks asset area in late May and early June 2020; these five Ray State wells have produced in aggregate approximately 1.6 million BOE in just over seven months of production; +• we completed and turned to sales five Leatherneck wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in late July and early August 2020; these five Leatherneck wells have produced in aggregate approximately 1.0 million BOE in just over six months of production; +• we completed and turned to sales the first 13 Boros wells, all of which were two-mile laterals, in the eastern portion of the Stateline asset area in a staggered fashion during September 2020; these 13 Boros wells have produced in aggregate approximately 2.7 million BOE in just over four months of production, despite a number of these wells being produced on restricted chokes early in their production; and +• San Mateo completed the expansion of the Black River Processing Plant and associated pipelines and facilities in conjunction with the Boros and Leatherneck wells coming online. +In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2020 included: +• the ongoing transition to drilling longer laterals, whereby 83% of the operated horizontal wells we completed and turned to sales in 2020 had lateral lengths greater than one mile, as compared to 29% in 2019 and 9% in 2018; +• the continuing improvement in capital efficiency as demonstrated by (i) our average drilling and completion costs for all operated horizontal wells completed and turned to sales of approximately $850 per lateral foot in 2020, a decrease of 27% as compared to average drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 44% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018, and (ii) the sequential quarterly decrease in our drilling and completion costs per lateral foot on operated wells turned to sales throughout 2020, from $1,009 in the first quarter to $881 in the second quarter to $790 in the third quarter and, finally, to $625 in the fourth quarter; +• record-low unit operating costs for lease operating expenses of $3.81 per BOE and general and administrative expenses of $2.27 per BOE; +• in our Wolf asset area, the results from our first Third Bone Spring Carbonate test in the Delaware Basin, demonstrating the prospectivity of this formation throughout the basin; and +• in our Rustler Breaks asset area, the results from our first Third Bone Spring Sand test, demonstrating the prospectivity of this formation in that asset area. +4 +Table of Contents +Financing Highlights +We concluded several important financing transactions in 2020 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the amendment of our third amended and restated credit agreement (the “Credit Agreement”) in February 2020 to reaffirm the borrowing base at $900.0 million, increase our elected borrowing commitment from $500.0 million to $700.0 million and add two new banks to our lending group; +• the reaffirmation of the borrowing base under the Credit Agreement in October 2020; and +• the restructuring of a portion of our then-existing 2020 NYMEX West Texas Intermediate (“WTI”) oil derivative financial instruments in April 2020 to provide additional revenue assurance had oil prices declined further and help us remain in compliance with our Credit Agreement leverage covenant in 2020. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Effective October 1, 2020, together with our joint venture partner, a subsidiary of Five Point Energy LLC (“Five Point”), we completed the successful merger of San Mateo II with and into San Mateo I. San Mateo is owned 51% by us and 49% by Five Point. +San Mateo achieved strong operating results in 2020, highlighted by (i) increased midstream services revenues, (ii) increased produced water handling volumes and (iii) increased oil gathering and transportation volumes, all as compared to 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but, on a quarterly sequential basis, San Mateo’s natural gas gathering and processing volumes, water handling volumes and oil gathering and transportation volumes all increased significantly in the fourth quarter of 2020, as compared to the third quarter, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant, which added an incremental designed inlet capacity of 200 MMcf of natural gas per day to the previously designed inlet capacity of 260 MMcf per day for a total designed inlet capacity of 460 MMcf per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2020, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo also completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). In addition, San Mateo completed and placed in service approximately 19 miles of various diameter crude oil pipelines from certain points of origin in the Greater Stebbins Area to the existing San Mateo interconnect with a subsidiary of Plains All American Pipeline, L.P. (“Plains”) in Eddy County, New Mexico. At December 31, 2020, San Mateo was gathering or transporting our oil and natural gas production via pipeline in both the Stateline asset area and the Greater Stebbins Area, as well as in the Wolf and Rustler Breaks asset areas. San Mateo was handling our produced water via pipeline in each of these areas as well. +At December 31, 2020, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 140 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large-diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 13 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 335,000 Bbl per day and approximately 120 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +5 +Table of Contents +Environmental, Social and Governance (“ESG”) Initiatives +We maintain an active ESG program and continued working in 2020 to improve upon our various ESG efforts. For instance, we significantly increased the percentage of new production facilities operating on electrical grid power, lowering emissions by removing on-site generators. We also increased the percentage of recycled water used in our completions and increased the percentage of both produced water and oil we transported via pipeline. +Using batch drilling and longer laterals, we significantly increased our lateral footage drilled per new pad built, helping to reduce our surface footprint. Finally, we continued our commitment to a proactive safety culture, with approximately 2.1 million employee man-hours and no lost time accidents experienced from 2017 to 2020. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2020, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2020. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +230,600 124,700 831 398.5 4,359 1,502 261,888 43.9 67,522 +South Texas: +Eagle Ford (5) +29,300 26,300 126 105.0 229 182 4,909 100.0 2,412 +Northwest Louisiana +Haynesville 16,700 9,100 237 18.8 163 16 3,486 100.0 5,015 +Cotton Valley (6) +16,100 14,900 64 39.7 154 35 49 100.0 226 +Area Total (7) +19,100 17,700 301 58.5 317 51 3,535 100.0 5,241 +Total 279,000 168,700 1,258 562.0 4,905 1,735 270,332 45.7 75,175 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2020. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2020, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of two miles or greater, and approximately 80% are expected to have lateral lengths of 1.5 miles or greater. At December 31, 2020, these engineered drilling locations included only 358 gross (145 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, in the Delaware Basin. At December 31, 2020, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale or the Haynesville shale, primarily as a result of the significantly lower oil and natural gas prices used to estimate proved reserves at December 31, 2020, which were $36.04 per Bbl and $1.99 per MMBtu, respectively, as compared to prior periods. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2020. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +6 +Table of Contents +We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2020, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2020, we also were the operator for approximately 93% of our Eagle Ford acreage and approximately 52% of our Haynesville acreage, including approximately 8% of our acreage in what we believe is the core area of the Haynesville play. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2020, our total acreage position in Southeast New Mexico and West Texas was approximately 230,600 gross (124,700 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 34,600 gross (18,400 net) acres in our Ranger asset area in Lea County, 66,000 gross (26,800 net) acres in our Arrowhead asset area in Eddy County, 47,900 gross (26,200 net) acres in our Rustler Breaks asset area in Eddy County, 23,200 gross (16,000 net) acres in our Antelope Ridge asset area in Lea County, 15,100 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our Stateline asset area in Eddy County and 40,500 gross (23,200 net) acres in our Twin Lakes asset area in Lea County at December 31, 2020. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2020, our acreage position in the Delaware Basin was approximately 67% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 79% held by existing production at December 31, 2020. +During the year ended December 31, 2020, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 89 gross (47.8 net) wells in the Delaware Basin, including 53 gross (45.6 net) operated horizontal wells and 36 gross (2.2 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2020, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, the Avalon, the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +7 +Table of Contents +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2020. Our average daily oil equivalent production from the Delaware Basin increased approximately 21% to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020, as compared to 55,599 BOE per day (84% of total oil equivalent production), including 35,184 Bbl of oil per day (92% of total oil production) and 122.5 MMcf of natural gas per day (73% of total natural gas production), in 2019. Our average daily oil equivalent production from the Delaware Basin also grew approximately 26% from 61,493 BOE per day in the fourth quarter of 2019 to 77,367 BOE per day in the fourth quarter of 2020. +At December 31, 2020, approximately 97% of our estimated total proved oil and natural gas reserves, or 261.9 million BOE, was attributable to the Delaware Basin, including approximately 156.3 million Bbl of oil and 633.5 Bcf of natural gas, a 12% increase, as compared to 232.8 million BOE for the year ended December 31, 2019. Our Delaware Basin proved reserves at December 31, 2020 comprised approximately 98% of our proved oil reserves and 96% of our proved natural gas reserves, as compared to approximately 94% of our proved oil reserves and 89% of our proved natural gas reserves at December 31, 2019. +At December 31, 2020, we had identified 4,359 gross (1,502 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,091 gross (1,298 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2020, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of two miles or greater and approximately 80% are expected to have horizontal lateral lengths greater than 1.5 miles. At and prior to December 31, 2019, all of our identified horizontal drilling locations were based on the assumptions of a one-mile lateral being drilled at each location. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2020 do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2020, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2020, these potential future drilling locations included 358 gross (145 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves. +At December 31, 2020, we were operating three drilling rigs in the Delaware Basin, and we expect to operate three rigs in the Delaware Basin during most of the first quarter of 2021. We expect to add a fourth rig in March 2021 and to operate four rigs in the Delaware Basin throughout the remainder of 2021. Two of these operated rigs are expected to operate full-time in the Stateline asset area. The other two rigs are expected to operate in certain of our other asset areas, including the Greater Stebbins Area, the Wolf asset area, the Ranger asset area and the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area. We have built significant optionality into our drilling program, which allowed us to decrease the number of rigs in 2020 from six to three within a few months and should generally allow us to increase or decrease the number of rigs we operate as necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2021. +Antelope Ridge Asset Area - Lea County, New Mexico +At the end of the first quarter of 2020, we achieved the first of the five operational milestones we set for Matador in 2020 when we completed and turned to sales our first six gross (6.0 net) wells on the Rodney Robinson leasehold. These wells also were the first wells drilled on acreage acquired in the BLM Acquisition. Including the Rodney Robinson wells, we completed and turned to sales 12 gross (11.4 net) operated and 15 gross (0.3 net) non-operated wells in the Antelope Ridge asset area during 2020. +The 1,200 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired as part of the of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. The six Rodney Robinson wells, which included two Wolfcamp A-XY completions, two Second Bone Spring completions, one Upper Avalon completion and one Lower Avalon completion, were turned to sales late in the first quarter of 2020 and were all two-mile laterals. The 24-hour initial potential (“IP”) test results from all six Rodney Robinson wells totaled 19,236 BOE per day (79% oil). Notably, these IP test results included, at the time, the best IP test results we had achieved for wells completed and turned to sales in the Avalon, Second Bone Spring and Wolfcamp A-XY formations throughout the Delaware Basin. These +8 +Table of Contents +six Rodney Robinson wells have produced in aggregate approximately 2.7 million BOE in approximately 10 months of production. We drilled four additional Rodney Robinson wells in the fall of 2020, and these four wells are expected to be completed and turned to sales late in the first quarter of 2021. +Rustler Breaks Asset Area - Eddy County, New Mexico +In the Rustler Breaks asset area, we completed and turned to sales 13 gross (7.8 net) operated wells and 21 gross (1.9 net) non-operated wells during 2020. +During the second quarter of 2020, we achieved the second of the five operational milestones we set for Matador in 2020 when we completed and turned to sales five wells on our Ray State leasehold in the eastern portion of the Rustler Breaks asset area in late May and early June. These five wells, which were all-two mile laterals, included two Wolfcamp A-XY completions, one Wolfcamp A-Lower completion and two Wolfcamp B-Blair completions. The 24-hour IP aggregate test results for the five Ray State wells were 12,507 BOE per day (61% oil). These five Ray State wells have produced in aggregate approximately 1.6 million BOE in just over seven months of production. +During the fourth quarter of 2020, we completed and turned to sales three wells on our Ace Stern Vegas leasehold in northeast Rustler Breaks, including two Wolfcamp A-XY completions and one Third Bone Spring completion. The 24-hour IP aggregate test results for these three wells, which were all two-mile laterals, were 7,415 BOE per day (74% oil). We believe these three wells demonstrate the prospectivity of the northeastern portion of our Rustler Breaks acreage. +Arrowhead, Ranger and Twin Lakes Asset Areas - Eddy and Lea Counties, New Mexico +During the third quarter of 2020, we achieved the third of the five operational milestones we set for Matador in 2020 when we completed and turned to sales five gross (4.3 net) operated wells, all of which were two-mile laterals, on the Leatherneck tract in the Greater Stebbins Area. These five Leatherneck wells have produced in aggregate approximately 1.0 million BOE in just over six months of production. We did not complete or turn to sales any other operated or non-operated wells in other portions of the Arrowhead asset area or in the Ranger or Twin Lakes asset areas during 2020. +We were pleased with the performance from the five Leatherneck wells, which included two Third Bone Spring completions, two Wolfcamp A-XY completions and one Wolfcamp B completion. The Wolfcamp B completion was particularly noteworthy, being our first test of the Wolfcamp B formation this far north in the Delaware Basin. This Wolfcamp B completion tested 2,101 BOE per day (71% oil) during its 24-hour IP test. We believe these results provide evidence of Wolfcamp B prospectivity moving north in the Delaware Basin. +Stateline Asset Area - Eddy County, New Mexico +We operated two drilling rigs in our Stateline asset area for the majority of 2020 and expect to do so again in 2021. In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net leasehold acres prospective for multiple geologic targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We plan to develop this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.5-mile laterals on the western side of the leasehold. We began drilling operations in the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we achieved the last two of the five operational milestones we set for Matador in 2020 when we completed and turned to sales our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area and connected these wells to the expanded Black River Processing Plant and associated pipeline and facilities discussed below. +The 13 Boros wells, all of which were two-mile laterals, tested six different intervals and included one Avalon completion, two Second Bone Spring completions, four Wolfcamp A-XY completions, four Wolfcamp A-Lower completions, one Wolfcamp B-Upper completion and one Wolfcamp B-Lower completion. In aggregate, these 13 Boros wells tested 45,225 BOE per day (56% oil), and the IP test results from the two Second Bone Spring completions were the top two IP test results that we had reported to date for wells completed and turned to sales in that formation throughout the Delaware Basin. Similarly, the IP test results for three of the Wolfcamp A-Lower completions were three of the top four IP test results that we had achieved to date for wells completed and turned to sales in the Wolfcamp A-Lower formation. In addition, most of these 24-hour IP test results were recorded at high flowing casing pressures of between 3,000 and 4,200 pounds per square inch (“psi”) in the Wolfcamp A-XY, Wolfcamp A-Lower and Wolfcamp B formations, further indicating the potential of these wells. These 13 Boros wells have produced in aggregate approximately 2.7 million BOE in just over four months of production, despite a number of these wells being produced on restricted chokes early in their production. +In addition, during 2020, we drilled 13 wells on the Voni tract on the western portion of the Stateline leasehold. These 13 Voni wells are expected to have completed lateral lengths of approximately 12,000 feet and should be completed in the first quarter of 2021 and turned to sales early in the second quarter of 2021. +9 +Table of Contents +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we completed and turned to sales 10 gross (9.1 net) operated wells during 2020. The Larson 04-TTT-B02 WF #136H (Larson #136H) well in the Wolf asset area was particularly significant, being our first test of the Third Bone Spring Carbonate formation in the Delaware Basin. The Larson #136H well tested 1,668 BOE per day (68% oil) from a completed lateral length of 7,443 feet. We believe this test result indicates the prospectivity of the Third Bone Spring Carbonate, not only in the Wolf asset area, but also in our other asset areas throughout the Delaware Basin. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2020, our properties included approximately 29,300 gross (26,300 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 87% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 99% of our Eagle Ford acreage was held by production at December 31, 2020. +We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2020. In fact, as of December 31, 2020, we had not completed any wells in the Eagle Ford shale in over 18 months. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 40% to 2,412 BOE per day, including 1,840 Bbl of oil per day and 3.4 MMcf of natural gas per day, during 2020, as compared to 4,009 BOE per day, including 3,113 Bbl of oil per day and 5.4 MMcf of natural gas per day, during 2019. For the year ended December 31, 2020, 3% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 6% for the year ended December 31, 2019. +At December 31, 2020, approximately 2% of our estimated total proved oil and natural gas reserves, or 4.9 million BOE, was attributable to the Eagle Ford shale, including approximately 3.6 million Bbl of oil and 7.8 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2020, as compared to approximately 6% of our proved oil reserves and 3% of our proved natural gas reserves at December 31, 2019. +At December 31, 2020, we had identified 229 gross (182 net) engineered locations for potential future drilling on our Eagle Ford acreage. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to almost two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2020, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the prospectivity of these intervals. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +10 +Table of Contents +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2020, although we did participate in the drilling and completion of four gross (less than 0.1 net) non-operated Haynesville shale wells that were turned to sales in 2020. In the first quarter of 2020, we leased 2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained royalty interests ranging from 18% to 20%. This lessee drilled four wells in the second half of 2020. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2021. +At December 31, 2020, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including 16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,800 net) acres that we consider to be in the core area of the Haynesville shale play. +For the year ended December 31, 2020, approximately 7% of our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2019, approximately 10% of our average daily oil equivalent production, or 6,595 BOE per day, including 15 Bbl of oil per day and 39.5 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2020, approximately 17% of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2019, approximately 24% of our daily natural gas production, or 39.5 MMcf of natural gas per day, was attributable to these properties. At December 31, 2020, just over 1% of our estimated total proved reserves, or 3.5 million BOE, was attributable to our properties in Northwest Louisiana. +At December 31, 2020, we had identified 163 gross (16 net) engineered locations for potential future drilling in the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to two miles, with most being two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other factors. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo I, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo I included (i) the Black River Processing Plant (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo I and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 23, 2021, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through February 23, 2021, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019 and 2020, and we expect Five Point to pay us an additional $14.7 million in performance incentives in the first quarter of 2021. We may earn up to the remaining $14.7 million in San Mateo I performance incentives over the next two years. In connection with the formation of San Mateo I, we dedicated to San Mateo I current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo I pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each +11 +Table of Contents +company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in deferred performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of 2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives from Five Point. At February 23, 2021, we had received $0.7 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo I. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2020, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2020, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area. +In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline. +At December 31, 2020, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2020, San Mateo gathered approximately 73.9 Bcf of natural gas, a decrease of 4%, as compared to 77.2 Bcf of natural gas gathered during the year ended December 31, 2019. In addition, during the year ended December 31, 2020, San Mateo processed approximately 60.8 Bcf of natural gas at the Black River Processing Plant, a decrease of 6%, as compared to 64.7 Bcf of natural gas processed during the year ended December 31, 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but San Mateo’s sequential natural gas gathering and processing volumes increased significantly in the fourth quarter of 2020, as compared to the third quarter of 2020, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer +12 +Table of Contents +producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +In 2020, San Mateo completed and placed into service (i) a crude oil gathering and transportation system in the Greater Stebbins Area, which was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2020, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. +At December 31, 2020, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains and two trucking facilities. During the year ended December 31, 2020, the San Mateo Oil Pipeline Systems had throughput of approximately 11.6 million Bbl of oil, an increase of 32%, as compared to throughput of approximately 8.9 million Bbl of oil during the year ended December 31, 2019. +Produced Water Gathering and Disposal Assets +During 2020, San Mateo placed into service one commercial salt water disposal well in the Rustler Breaks asset area, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to eight. In addition to its eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, at February 23, 2021, San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, two commercial salt water disposal wells and associated facilities in the Greater Stebbins Area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 23, 2021, San Mateo had designed disposal capacity of approximately 335,000 Bbl of produced water per day. +During the year ended December 31, 2020, San Mateo handled approximately 84.8 million Bbl of produced water, an increase of 15%, as compared to approximately 73.9 million Bbl of produced water handled during the year ended December 31, 2019. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases and from third parties. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2020, 2019 and 2018. +Year Ended December 31, +2020 2019 2018 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 15,931 13,984 11,141 +Natural gas (Bcf) 69.5 61.1 47.3 +Total oil equivalent (MBOE) (1) +27,514 24,164 19,026 +Average daily production (BOE/d) (1) +75,175 66,203 52,128 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 37.38 $ 54.34 $ 57.04 +Oil, with realized derivatives (per Bbl) $ 39.83 $ 54.98 $ 57.38 +Natural gas, without realized derivatives (per Mcf) $ 2.14 $ 2.17 $ 3.49 +Natural gas, with realized derivatives (per Mcf) $ 2.14 $ 2.18 $ 3.46 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 3.39 $ 3.82 $ 4.00 +Lease operating $ 3.81 $ 4.85 $ 4.89 +Plant and other midstream services operating $ 1.51 $ 1.52 $ 1.29 +Depletion, depreciation and amortization $ 13.15 $ 14.51 $ 13.94 +General and administrative $ 2.27 $ 3.31 $ 3.64 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 15,254 674 — 3 15,931 +Natural gas (Bcf) 56.8 1.2 11.0 0.5 69.5 +Total oil equivalent (MBOE) (3) +24,713 883 1,835 83 27,514 +Percentage of total annual net production 89.8 % 3.2 % 6.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 41,678 1,840 — 8 43,526 +Natural gas (MMcf/d) 155.1 3.4 30.1 1.3 189.9 +Total oil equivalent (BOE/d) 67,522 2,412 5,015 226 75,175 +Average Sales Prices (4) +Oil (per Bbl) $ 37.38 $ 37.42 $ 28.77 $ 38.31 $ 37.38 +Natural gas (per Mcf) $ 2.23 $ 2.82 $ 1.66 $ 1.69 $ 2.14 +Total oil equivalent (per BOE) $ 28.19 $ 32.56 $ 9.94 $ 11.09 $ 27.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.52 $ 20.52 $ 4.71 $ 19.39 $ 5.09 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 12,843 1,136 — 5 13,984 +Natural gas (Bcf) 44.7 2.0 13.9 0.5 61.1 +Total oil equivalent (MBOE) (3) +20,294 1,463 2,316 91 24,164 +Percentage of total annual net production 84.0 % 6.0 % 9.6 % 0.4 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 35,184 3,113 — 15 38,312 +Natural gas (MMcf/d) 122.5 5.4 38.1 1.4 167.4 +Total oil equivalent (BOE/d) 55,599 4,009 6,345 250 66,203 +Average Sales Prices (4) +Oil (per Bbl) $ 53.95 $ 58.71 $ — $ 52.89 $ 54.34 +Natural gas (per Mcf) $ 2.11 $ 3.45 $ 2.16 $ 2.17 $ 2.17 +Total oil equivalent (per BOE) $ 38.80 $ 50.22 $ 12.99 $ 15.22 $ 36.93 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.22 $ 15.27 $ 4.36 $ 22.43 $ 5.81 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 10,230 907 — 4 11,141 +Natural gas (Bcf) 37.7 1.5 7.5 0.6 47.3 +Total oil equivalent (MBOE) (3) +16,512 1,152 1,247 115 19,026 +Percentage of total annual net production 86.8 % 6.0 % 6.6 % 0.6 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 28,026 2,485 — 13 30,524 +Natural gas (MMcf/d) 103.3 4.0 20.5 1.8 129.6 +Total oil equivalent (BOE/d) 45,237 3,158 3,417 316 52,128 +Average Sales Prices (4) +Oil (per Bbl) $ 56.12 $ 67.4 $ — $ 64.72 $ 57.04 +Natural gas (per Mcf) $ 3.55 $ 5.46 $ 2.85 $ 2.80 $ 3.49 +Total oil equivalent (per BOE) $ 42.88 $ 60.02 $ 17.09 $ 18.59 $ 42.08 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.79 $ 17.25 $ 5.41 $ 19.11 $ 5.68 +_________________ +(1) Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020 increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31, 2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for the year ended December 31, 2019. +Our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019 increased 27% from our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, as compared to 52,128 BOE per day for the year ended December 31, 2018. Our average daily oil production for the year ended December 31, 2019 was 38,312 Bbl of oil per day, an increase of 26% from 30,524 Bbl of oil per day for the year ended December 31, 2018. Our average daily natural gas production for the year ended December 31, 2019 was 167.4 MMcf of natural gas per day, an increase of 29% from 129.6 MMcf of natural gas per day for the year ended December 31, 2018. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2020. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 79% in all wells that we operated at December 31, 2020. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +673 322.1 158 76.4 831 398.5 +South Texas: +Eagle Ford (2) +122 101.0 4 4.0 126 105.0 +Northwest Louisiana: +Haynesville — — 237 18.8 237 18.8 +Cotton Valley (3) +1 1.0 63 38.7 64 39.7 +Area Total 1 1.0 300 57.5 301 58.5 +Total 796 424.1 462 137.9 1,258 562.0 +__________________ +(1) Includes 219 gross (62.6 net) vertical wells that were acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2020, 2019 and 2018. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +17 +Table of Contents +At December 31, (1) +2020 2019 2018 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 159,949 147,991 123,401 +Natural Gas (Bcf) 662.3 627.2 551.5 +Total (MBOE) (3) +270,332 252,531 215,313 +Estimated proved developed reserves: +Oil (MBbl) 69,647 59,667 53,223 +Natural Gas (Bcf) 323.2 276.3 246.2 +Total (MBOE) (3) +123,507 105,710 94,261 +Percent developed 45.7 % 41.9 % 43.8 % +Estimated proved undeveloped reserves: +Oil (MBbl) 90,301 88,324 70,178 +Natural gas (Bcf) 339.1 351.0 305.2 +Total (MBOE) (3) +146,825 146,821 121,052 +Standardized Measure (4) (in millions) +$ 1,584.4 $ 2,034.0 $ 2,250.6 +PV-10 (5) (in millions) +$ 1,658.0 $ 2,248.2 $ 2,579.3 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas, for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas and for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2020, 2019 and 2018 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2020, 2019 and 2018 were, in millions, $73.6, $214.2 and $328.7, respectively. +Our estimated total proved oil and natural gas reserves increased 7% from 252.5 million BOE at December 31, 2019 to 270.3 million BOE at December 31, 2020. This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2020. This increase in total proved reserves was achieved despite (i) the reduction in our operated rig count from six to three during 2020 and (ii) the 31% reduction in oil price and the 23% reduction in natural gas price used to estimate total proved reserves at December 31, 2020, as compared to December 31, 2019. We added 35.3 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2020, approximately 1.3 times our 2020 annual production of 27.5 million BOE. We also realized approximately 9.8 million BOE in net upward revisions to our proved reserves during 2020, primarily as a result of upward revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2019, which more than offset the downward revisions resulting from the significantly lower commodity prices used to estimate proved reserves at December 31, 2020. Our proved oil reserves grew 8% from approximately 148.0 million Bbl at December 31, 2019 to approximately 159.9 million Bbl at December 31, 2020. Our proved natural gas reserves increased 6% from 627.2 Bcf at December 31, 2019 to 662.3 Bcf at December 31, 2020. Our proved reserves to production ratio at December 31, 2020 was 9.8, a decrease of 7% from 10.5 at December 31, 2019. +Over the past two years, our estimated total proved oil and natural gas reserves increased 26% from 215.3 million BOE at December 31, 2018 to 270.3 million Bbl at December 31, 2020. Our proved oil reserves grew 30% from 123.4 million Bbl at December 31, 2018 to 159.9 million Bbl at December 31, 2020. Our proved developed oil reserves increased 31% from 53.2 million Bbl at December 31, 2018 to 69.6 million Bbl at December 31, 2020. +18 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves decreased 22% from $2.03 billion at December 31, 2019 to $1.58 billion at December 31, 2020. The PV-10 of our total proved oil and natural gas reserves decreased 26% from $2.25 billion at December 31, 2019 to $1.66 billion at December 31, 2020. The decreases in our Standardized Measure and PV-10 are primarily a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2020 were $36.04 per Bbl and $1.99 per MMBtu, a decrease of 31% and 23%, respectively, as compared to average oil and natural gas prices of $52.19 per Bbl and $2.58 per MMBtu used to estimate proved reserves at December 31, 2019. Our total proved reserves were made up of 59% oil and 41% natural gas at both December 31, 2020 and December 31, 2019. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +Our proved developed oil and natural gas reserves increased 17% from 105.7 million BOE at December 31, 2019 to 123.5 million BOE at December 31, 2020 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 17% from 59.7 million Bbl at December 31, 2019 to 69.6 million Bbl at December 31, 2020. Our proved developed natural gas reserves increased 17% from 276.3 Bcf at December 31, 2019 to 323.2 Bcf at December 31, 2020. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2020. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2019 105,710 +Extensions and discoveries 15,217 +Net acquisitions of minerals-in-place 190 +Revisions of prior estimates 960 +Production (27,514) +Conversion of proved undeveloped to proved developed 28,944 +As of December 31, 2020 123,507 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves were 146.8 million BOE at both December 31, 2019 and December 31, 2020, as the net additions to our proved undeveloped reserves of 28.9 million BOE offset the 28.9 million BOE we converted from proved undeveloped to proved developed reserves during 2020. Our proved undeveloped oil reserves increased 2% from 88.3 million Bbl at December 31, 2019 to 90.3 million Bbl at December 31, 2020. Our proved undeveloped natural gas reserves decreased 3% from 351.0 Bcf at December 31, 2019 to 339.1 Bcf at December 31, 2020. These changes in proved undeveloped oil and natural gas reserves were primarily the result of net increases in proved undeveloped reserves in the Delaware Basin resulting from our delineation and development operations there, which were offset by the conversion of proved undeveloped reserves to proved developed reserves and the removal of certain proved undeveloped reserves from total proved reserves at December 31, 2020, primarily as a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. +At December 31, 2020, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2020 within five years of booking these reserves. +19 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2020. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2019 146,821 +Extensions and discoveries 20,080 +Revisions of prior estimates 8,868 +Conversion of proved undeveloped to proved developed (28,944) +As of December 31, 2020 146,825 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2017, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2017 9,300 45.0 16,808 $ 211,860 +2018 16,009 61.7 26,283 356,830 +2019 13,832 58.8 23,629 318,609 +2020 16,256 76.1 28,944 257,590 +Total 55,397 241.6 95,664 $ 1,144,889 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2020. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 156,309 633.5 261,888 $ 1,538.2 $ 1,609.7 +South Texas: +Eagle Ford (5) +3,610 7.8 4,909 37.4 39.1 +Northwest Louisiana +Haynesville — 20.9 3,486 8.6 9.0 +Cotton Valley (6) +30 0.1 49 0.2 0.2 +Area Total 30 21.0 3,535 8.8 9.2 +Total 159,949 662.3 270,332 $ 1,584.4 $ 1,658.0 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2020 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2020 were approximately $73.6 million. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +20 +Table of Contents +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. For 2020, our Executive Vice President of Reservoir Engineering and Chief Technology Officer was primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 43 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2020. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 165,800 83,300 64,800 41,400 230,600 124,700 +South Texas: +Eagle Ford 28,900 26,100 400 200 29,300 26,300 +Northwest Louisiana: +Haynesville 16,700 9,100 — — 16,700 9,100 +Cotton Valley 16,100 14,900 — — 16,100 14,900 +Area Total (1) +19,100 17,700 — — 19,100 17,700 +Total 213,800 127,100 65,200 41,600 279,000 168,700 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +21 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2020 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2026 and beyond totals 6,800 net acres, all of which is in the Delaware Basin. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2020. +Acres Acres Acres Acres Acres +Expiring 2021 Expiring 2022 Expiring 2023 Expiring 2024 Expiring 2025 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +29,300 15,800 19,600 10,200 5,600 5,200 1,300 1,100 2,300 2,300 +South Texas: +Eagle Ford 400 200 — — — — — — — — +Total 29,700 16,000 19,600 10,200 5,600 5,200 1,300 1,100 2,300 2,300 +__________________ +(1) Approximately 47% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our 2021 drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2020, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2020, 2019 and 2018 . +Year Ended December 31, +2020 2019 2018 +Gross Net Gross Net Gross Net +Development Wells +Productive 89 44.5 147 62.0 118 54.7 +Dry — — — — — — +Exploration Wells +Productive 4 3.3 25 13.3 35 20.8 +Dry — — — — — — +Total Wells +Productive 93 47.8 172 75.3 153 75.5 +Dry — — — — — — +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +22 +Table of Contents +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, domestic or global health concerns such as COVID-19, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2020, 2019 and 2018, we had two, two and four significant purchasers that accounted for approximately 65%, 67% and 60%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” in January 2021, the Biden administration issued certain orders limiting the issuance of federal drilling permits and other necessary federal approvals. The +23 +Table of Contents +impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems in production and markets relating to a particular area could have a material impact on our business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, +24 +Table of Contents +the prohibition, restriction or limitation of venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior dated January 20, 2021 providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The impact of the federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 66 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not +25 +Table of Contents +unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would have started at $0.60 per MMBtu in 2020 and escalated to $3.00 per MMBtu by 2024. Although the bill did not pass, any such surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows” and “Risk Factors—Risks Related to Laws and Regulations—The Tax Cuts and Jobs Act may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers to fully offset our taxable income in future periods.” +26 +Table of Contents +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs +27 +Table of Contents +and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015 rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and the promulgation of the NWPR. +Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the U.S. Fish and Wildlife Service (the “USFWS”) under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order is currently on appeal in the Ninth Circuit Court of Appeals. However, the Montana district court’s decision spawned other NWP 12-based challenges and may indicate that the rest of the NWPs, some of which are relied upon for oil and natural gas projects, are vulnerable to similar challenge. The Corps has proposed a new set of NWPs, which would replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but has so far elected not to consult with the USFWS. If this status quo does not change, when the Corp re-issues the NWPs, the NWPs could be subject to the same legal challenges unless and until the ongoing litigation resolves the questions surrounding the need for a formal ESA consultation. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April +28 +Table of Contents +2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Following that executive order, the New Mexico Oil Conservation Division (the “NMOCD”), New Mexico Environment Department (the “NMED”) and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions that would, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and +29 +Table of Contents +political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, they could have an adverse impact on our business, financial condition, results of operations and cash flows. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +As of December 31, 2020, approximately 28% of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain +30 +Table of Contents +relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. +Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2020, we had 288 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +31 +Table of Contents +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2020, for example, our employees completed approximately 15,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2020, we estimate our employees have worked approximately 2.1 million combined hours without experiencing a single lost time accident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group, which is devoted to proactively minimizing safety risks and addressing any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +32 +Table of Contents +Item 1A. Risk Factors. +Summary of Risk Factors +The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed risk factors contained below. +Risks Related to our Financial Condition +• Our success is dependent on the prices of oil and natural gas, the volatility of which may adversely affect our financial condition. +• We face numerous risks related to the COVID-19 global pandemic, including its impact on global oil demand. +• Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. +• Our oil and natural gas reserves are estimated and may not reflect the actual volumes we will recover, and we may be required to write down the carrying value of our proved properties under accounting rules. +• Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +• Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +• An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our financial condition. +• A component of our growth may come through acquisitions, which we may be unable to complete or which may require us to incur certain liabilities, risks or title deficiencies. +• Our ability to complete dispositions of assets may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +Risks Related to our Liquidity +• We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. +• The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and San Mateo’s revolving credit facility (the “San Mateo Credit Facility”). +• The terms of the agreements governing our indebtedness impose significant operating and financial restrictions. +• Our credit rating may be downgraded, which could reduce our financial flexibility and increase interest expense. +• The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +Risks Related to our Operations +• Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational, geological and financial risk, and insurance against all such risks is not available to us. +• Because our reserves and production are concentrated in a few core areas, problems in production and markets relating to a particular area could have a material impact on our business. +• There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, and multi-well pad drilling may result in volatility in our operating results. +• Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. +• The unavailability or high cost of equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. +• We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. +33 +Table of Contents +• Regulatory changes could prevent our ability to continue to pool wells in the manner we have been. +• Midstream projects are subject to risks of construction delays and cost over-runs. +• Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter our plans. +Risks Related to Third Parties +• We depend upon several significant purchasers for the sale of most of our production, and financial difficulties encountered by such purchasers, other operators or third parties could decrease our cash flows from operations. +• The marketability of our production is dependent upon gathering, processing and transportation facilities. +• We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. +• Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products. +• We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput. +• Competition in our industry is intense, making it more difficult for us to acquire properties, market production, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources. +• We have limited control over activities on properties we do not operate. +Risks Related to Laws and Regulations +• As of December 31, 2020, approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations. +• We are subject to government regulation, including environmental laws, which could require significant expenditures. +• We are subject to tax laws, and changes thereto could eliminate or reduced certain federal income tax deductions or net operating loss carryforwards currently available. +• Legislative and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs, operating restrictions or delays. +• We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations, and the rates of our regulated assets are subject to oversight by regulators, which could adversely affect our revenues. +• Derivatives legislation adopted by Congress could limit our ability to hedge commodity price risks. +Risks Relating to Our Common Stock +• The price of our common stock is volatile and may fluctuate substantially in the future. +• Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect our stock price. +• Our directors and executive officers own a significant percentage of our equity, which could give them influence in transactions and other matters, and their interests could differ from other shareholders. +• Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +General Risk Factors +• We may have difficulty managing growth in our business. +• Our success depends on our ability to retain our key personnel. +• If we fail to maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. +• A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +• Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. +• We operate in a litigious environment and may be involved in legal proceedings that could have an adverse effect on our results of operations and financial condition. +34 +Table of Contents +Risks Related to our Financial Condition +Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations. +The prices we receive for the oil and natural gas we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2020, oil prices averaged $39.34 per Bbl, ranging from a high of $63.27 per Bbl in early January to a low of ($37.63) per Bbl in mid-April, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2020, natural gas prices averaged $2.13 per MMBtu, as compared to $2.53 per MMbtu for the year ended December 31, 2019, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2020, natural gas prices began the year at $2.12 per MMBtu and fell to a low of $1.48 per MMBtu at the end of June, before increasing to a high of $3.35 per MMBtu in late October and finishing the year at $2.54 per MMBtu. +Because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. The significant decline in oil and natural gas prices during 2020 caused us to recognize full-cost ceiling impairments in each of the second, third and fourth quarters of 2020, and we may recognize further full-cost ceiling impairments in future periods. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• the domestic and foreign supply of, and demand for, oil and natural gas; +• the actions of OPEC+ and state-controlled oil companies relating to oil price and production controls; +• the prices and availability of competitors’ supplies of oil and natural gas; +• the price and quantity of foreign imports; +• the impact of U.S. dollar exchange rates; +• domestic and foreign governmental regulations and taxes; +• speculative trading of oil and natural gas futures contracts; +• the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; +• the availability of refining capacity; +• the prices and availability of alternative fuel sources; +• weather conditions and natural disasters; +• political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America and Russia; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19; +• the continued threat of terrorism and the impact of military action and civil unrest; +• public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; +• the level of global oil and natural gas inventories and exploration and production activity; +• the impact of energy conservation efforts; +• technological advances affecting energy consumption; and +• overall worldwide economic conditions. +35 +Table of Contents +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil and natural gas prices do not necessarily fluctuate in direct relation to each other. +During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant +decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices +was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of +COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to +increase its oil production to world markets following the failure of efforts by OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. Primarily as a result of these unexpected events and the resulting declines in oil prices, we significantly modified our 2020 operational plan. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +We face numerous risks related to the COVID-19 global pandemic, which has had and is likely to continue to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which have materially reduced global demand for crude oil. The extent to which COVID-19 will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information that may emerge concerning the severity of COVID-19 and the effectiveness of vaccines and other actions taken to contain COVID-19 or treat its impact now or in the future, among others. +Some impacts of the COVID-19 pandemic that could have an adverse effect on our business, financial condition, results of operations and cash flows include: +• significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production; +• further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result, in part, of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19; +• increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces; +• significant decreases in the volumes of oil, natural gas and produced water that are transported, gathered, processed or disposed of by San Mateo due to curtailed or shut-in production by Matador or other of San Mateo’s customers; +• increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate; +• increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints; +• the potential for the operations of the Black River Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 among the relevant workforce; +• the potential for forced curtailment of oil and natural gas production by state governmental agencies, resulting in a need to significantly curtail or shut in our production; +36 +Table of Contents +• the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing; +• increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage or the failure of certain of our counterparties to continue as going concerns; +• increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions; +• the potential impact for delays in construction or increased costs related to midstream construction projects; +• increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and +• increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations. +The COVID-19 outbreak continues to evolve, and the extent to which the outbreak may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired. +Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• our estimated proved oil and natural gas reserves; +• the amount of oil and natural gas we produce; +• the prices at which we sell our production; +• the costs of developing and producing our oil and natural gas reserves; +• the costs of constructing, operating and maintaining our midstream facilities; +• our ability to attract third-party customers for our midstream services; +• our ability to acquire, locate and produce new reserves; +• the ability and willingness of banks to lend to us; and +• our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund +37 +Table of Contents +acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. +Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• the quality and quantity of available data; +• the interpretation of that data; +• the judgment of the persons preparing the estimate; and +• the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• actual prices we receive for oil and natural gas; +• actual costs and timing of development and production expenditures; +• the amount and timing of actual production; and +• changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles (“GAAP”) is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +38 +Table of Contents +Approximately 54% of our total proved reserves at December 31, 2020 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +At December 31, 2020, approximately 54% of our total proved reserves were undeveloped and less than 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on increasing our production and reserves from the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have: +• downward adjustments to our estimated proved reserves; +• increases in our estimates of development costs; or +• deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the +39 +Table of Contents +call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2020. +An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows. +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. +Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in 2020, these price differentials could turn negative and widen again in future periods. Should we experience future periods of negative pricing for natural gas as we did at certain times in 2020, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. We have limited oil basis hedges in place to mitigate our exposure to oil price differentials during 2021 and 2022, and we have no derivative contracts in place to mitigate our exposure to natural gas price differentials. +A component of our growth may come through acquisitions, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity +40 +Table of Contents +securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations. +Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost. +It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +41 +Table of Contents +Risks Related to our Liquidity +We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs. +As of February 23, 2021, the maximum facility amount under the Credit Agreement was $1.5 billion, the borrowing base was $900.0 million and our elected borrowing commitment was $700.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenant noted below). At February 23, 2021, we had available borrowing capacity of approximately $224.2 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.00 or less. +As of February 23, 2021, the facility amount under the San Mateo Credit Facility was $375.0 million, and San Mateo had available borrowing capacity of approximately $43.0 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $400.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. In addition to these restrictions, the San Mateo Credit Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may +42 +Table of Contents +incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• increasing our vulnerability to general adverse economic and industry conditions; +• placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• increasing the risk that we may default on our debt obligations. +The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 23, 2021, our borrowing base was $900.0 million, our elected borrowing commitment was $700.0 million and we had $430.0 million in outstanding borrowings under, and approximately $45.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement. As of February 23, 2021, the maximum facility amount under the Credit Agreement was $1.5 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenant noted above). We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement), plus 1.0%, plus, in each case, an amount ranging from 0.25% to 1.25% per annum depending on the level of borrowings under the Credit Agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25% to 2.25% per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 0.50% to 1.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50% to 2.50% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +As noted above, under the Credit Agreement and the San Mateo Credit Facility, borrowings in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Each of the Credit Agreement and the San Mateo Credit Facility specify that in the event that LIBOR cannot be determined or other conditions exist with respect to LIBOR, a replacement interest rate that gives due consideration to the then-prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time may be established by +43 +Table of Contents +the respective administrative agents, in consultation with us. If such an event occurs and we are unable to agree upon a replacement interest rate with our respective administrative agents, we could be unable to make borrowings in the form of Eurodollar loans and would have to borrow funds at the higher base rate, which could increase our cost of capital. Furthermore, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR. An increase in our cost of capital or a disruption in the financial market could have an adverse effect on our business and financial condition. +The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions. +Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• incur or guarantee additional debt or issue certain types of preferred stock; +• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• transfer or sell assets; +• make certain investments; +• create certain liens; +• enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• consolidate, merge or transfer all or substantially all of our assets; +• engage in transactions with affiliates; and +• create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. +Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is defined as consolidated total funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations. +In March 2020, our corporate credit rating from Standard & Poor’s Rating Services was downgraded from “B+” to “B-” and our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades resulted in significant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services upgraded our corporate credit rating in July 2020 to “B2.” As of February 23, 2021, our corporate credit ratings from Standard & Poor’s Rating Services and Moody’s Investors Service remained “B-” and “B2,” respectively. We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency +44 +Table of Contents +if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +On February 22, 2021, we declared our first quarterly dividend of $0.025 per share, and we intend to continue to pay a quarterly dividend in the future pursuant to a dividend policy adopted by our Board of Directors. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available. +We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price. +Risks Related to our Operations +Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• general economic and industry conditions, including the prices received for oil and natural gas; +• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• potential drainage of oil and natural gas from our properties by adjacent operators; +• the existence or magnitude of faults or unanticipated geological features; +• loss of or damage to oilfield development and service tools; +• accidents, equipment failures or mechanical problems; +45 +Table of Contents +• title defects of the underlying properties; +• increases in severance taxes; +• adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• domestic and foreign governmental regulations; and +• proximity to and capacity of gathering, processing and transportation facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +• landing our wellbore in the desired drilling zone; +• staying in the desired drilling zone while drilling horizontally through the formation; +• running our casing the entire length of the wellbore; +• fracture stimulating the planned number of stages; +• drilling out the plugs between stages following hydraulic fracturing operations; and +• being able to run tools and other equipment consistently through the horizontal wellbore. +Each of these risks is magnified in wells with longer laterals. In 2020, 74% of the operated wells we turned to sales had lateral lengths of two miles. In 2021, we anticipate that 98% of the operated wells we turn to sales should have lateral lengths of two miles or greater. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• natural disasters; +• adverse weather conditions; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19; +• loss of drilling fluid circulation; +• blowouts where oil or natural gas flows uncontrolled at a wellhead; +• cratering or collapse of the formation; +• pipe or cement leaks, failures or casing collapses; +• damage to pipelines, processing plants and disposal wells and associated facilities; +• fires or explosions; +• releases of hazardous substances or other waste materials that cause environmental damage; +• pressures or irregularities in formations; and +• equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Black River Processing Plant owned by San Mateo and operated by us. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from +46 +Table of Contents +processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected. +Insurance against all operational risks is not available to us. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because our reserves and production are concentrated in a few core areas, problems in production and markets relating to a particular area could have a material impact on our business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 90% of our total oil and natural gas production for 2020 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2021 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, including in February 2021, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut-ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other +47 +Table of Contents +operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value. +As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows. +Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. +Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. +Multi-well pad drilling may result in volatility in our operating results. +We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. +The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows. +Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial +48 +Table of Contents +difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could have a material adverse impact on our future production results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity. +From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of salt water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile become +49 +Table of Contents +increasingly common in the Delaware Basin, we will have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our drilling locations on federal lands may not be drilled as scheduled. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. +At December 31, 2020, we had leasehold interests in approximately 34,800 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2026. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Risks Related to Third Parties +Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the years ended December 31, 2020, 2019 and 2018, we had two, two and four significant purchasers, respectively, that collectively accounted for approximately 65%, 67% and 60%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows. +In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +50 +Table of Contents +The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas, which would decrease the volumes sold from our wells, and, in certain circumstances, would require us to pay royalties on such flared natural gas. +The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2021. If we were required to shut in our production or flare our natural gas for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows. +We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for San Mateo and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows. +51 +Table of Contents +Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s control. Any decrease in supplies to its midstream facilities could adversely affect San Mateo’s business and operating results. +San Mateo’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Our reduced drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2020, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $1.1 billion over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may +52 +Table of Contents +force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, Board of Directors and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +We have limited control over activities on properties we do not operate. +We are not the operator on some of our properties, particularly in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• the timing and amount of capital expenditures; +• the operator’s expertise and financial resources; +• the rate of production of reserves, if any; +• approval of other participants in drilling wells; and +• selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +Risks Related to Laws and Regulations +Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands. +At December 31, 2020, Matador held approximately 124,700 net leasehold and mineral acres in the Delaware Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 34,500 net acres, or about 28%, were on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can +53 +Table of Contents +take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements that may be implemented, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. The change in the presidential administration may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for: +• personal injuries; +• property damage; +• containment and clean-up of oil, produced water and other spills; +• management and disposal of hazardous materials; +• remediation, clean-up costs and natural resource damages; and +• other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are +54 +Table of Contents +drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA). +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Furthermore, we participate in candidate conservation agreements for the lesser prairie-chicken, the sand dune lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. Participation in such agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have an adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. +Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The Tax Cuts and Jobs Act did not include any of these proposals, except for the repeal of the domestic manufacturing tax deduction for oil and natural gas companies. It is possible, however, that such provisions could be proposed in the future. The passage of any legislation or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +In 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would have started at $0.60 per MMBtu in 2020 and escalated to $3.00 per MMBtu by 2024. Although the bill did not pass, any such surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. +The Tax Cuts and Jobs Act may impact our ability to fully utilize our interest expense deductions and net operating loss carryforwards to fully offset our taxable income in future periods. +The Tax Cuts and Jobs Act includes provisions that generally (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our business interest income) for the year, (ii) permit us to offset only 80% (rather than 100%) of our taxable income with net operating losses we generate and (iii) limit our ability to deduct certain elements of executive compensation. Interest expense and net operating losses subject to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the Tax Cuts and Jobs Act repealed the domestic manufacturing tax deduction for oil and natural gas companies. These tax law changes could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might not have incurred otherwise, in the absence of these tax law changes. +55 +Table of Contents +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands. These rules were rescinded by rule in December 2017; however, in January 2018, California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the rules. The Northern District of California upheld the rescission in 2020, but this decision was then appealed to the Ninth Circuit Court of Appeals. This litigation is ongoing and future implementation of the BLM rules is uncertain at this time. +Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. At various times during his campaign, President Biden indicated support for prohibitions of hydraulic fracturing on federal lands or outright. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Recently, bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders at the local, state or federal level could limit our operations. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. We and San Mateo dispose +56 +Table of Contents +of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could decrease San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Following that executive order, the NMOCD, NMED and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions that would, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and natural gas industry. While in August 2020, the EPA rescinded or modified certain methane and volatile organic compound emissions standards for oil and natural gas operations, President Biden has requested the EPA to consider establishing new emissions standards. Any future international agreements, federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs, adversely affecting our profits, and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our Operations—If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory +57 +Table of Contents +programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. +President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and it is expected that new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, or prohibiting or restricting oil and natural gas development activities in certain areas, will be proposed and/or promulgated during the Biden administration. In addition, the Biden administration has already issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before 2050 is a critical priority, affirmed his administration’s desire to establish the United States as a leader in addressing climate change and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes. +New regulations on all emissions from our operations could cause us to incur significant costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. The BLM then finalized a revised rule in 2018 that scaled back the waste-prevention requirements of the 2016 rule, but this revised rule was vacated by a California federal district court in 2020, a decision which the BLM has appealed to the Ninth Circuit Court of Appeals. If not withdrawn or significantly revised, these rules are expected to result in an increase to our operating costs and changes in our operations. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations. +We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to +58 +Table of Contents +develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. +The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.2 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +59 +Table of Contents +The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +Risks Relating to Our Common Stock +The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2020, our stock price fluctuated between a high of $19.83 and a low of $1.11. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• declaration of dividends or adjustments to our dividend policy; +• speculation in the press or investment community; +• announcement or consummation of acquisitions, dispositions or joint ventures by us; +• public reaction to our operations or plans, press releases, announcements and filings with the SEC; +• the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; +• the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations, such as the Biden Administration Federal Lease Orders; +60 +Table of Contents +• sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19; +• the realization of any of the risk factors presented in this Annual Report; +• the recruitment or departure of key personnel; +• commencement of, involvement in or unfavorable resolution of litigation; +• the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• changes in market valuations of companies similar to ours; and +• domestic and international economic, legal and regulatory factors unrelated to our performance. +Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price. +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors have published ESG disclosure standards that companies in which they invest are expected to adopt or follow. Furthermore, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. +Certain other stakeholders have pressured commercial and investment banks to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale play arena. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected. +Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and the interests of our directors and executive officers could differ from other shareholders. +As of February 23, 2021, our directors and executive officers beneficially owned approximately 7% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other +61 +Table of Contents +shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +General Risk Factors +We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team, the members of our Board and our special Board advisors, and the loss of any key personnel, Board member or special Board advisor could disrupt our business operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +If we fail to maintain effective internal control over financial reporting in the future, our ability to accurately report our financial results could be adversely affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management. +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial +62 +Table of Contents +processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our supervisory control and data acquisition (SCADA) systems, control important processes and facilities that are critical to our operations. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. +While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• authorization for our Board of Directors to issue preferred stock without shareholder approval; +• a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• the prohibition of cumulative voting in the election of directors; and +• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +We operate in a litigious environment and may be involved in legal proceedings that could have an adverse effect on our results of operations and financial condition. +Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Item 1B. Unresolved Staff Comments. +Not applicable. +63 +Table of Contents +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows. +On November 4, 2019, we received a Notice of Violation and Finding of Violation from the EPA and a Notice of Violation from the NMED alleging violations of the CAA and New Mexico State Implementation Plan at certain of our operated locations in New Mexico. We have provided information to the EPA and NMED and are engaged in discussions regarding a resolution of the alleged violations. We believe it is remote that the resolution of this matter will have a material adverse impact on our financial condition, results of operations or cash flows. Resolution of the matter may result in monetary sanctions of more than $300,000. +Item 4. Mine Safety Disclosures. +Not applicable. +64 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 23, 2021, we had 116,764,838 shares of common stock outstanding held by approximately 350 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2020. +Equity Compensation Plan Information +Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1)(2) +4,374,342 $ 23.08 1,940,386 +Equity compensation plans not approved by security holders — — — +Total 4,374,342 $ 23.08 1,940,386 +__________________ +(1) Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan (the “2003 Incentive Plan”) or the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). +(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board of Directors in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report. +65 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2015 through December 31, 2020, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +66 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2020, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2020 to October 31, 2020 365 $ 7.07 — — +November 1, 2020 to November 30, 2020 — — — — +December 1, 2020 to December 31, 2020 96 12.07 — — +Total +461 $ 8.11 — — +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +67 +Table of Contents +Item 6. Selected Financial Data. +Not applicable. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the impact of the worldwide spread of COVID-19 on oil and natural gas demand, oil and natural gas prices and our business, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +For a comparison of our results of operations for the years ended December 31, 2019 and December 31, 2018, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on March 2, 2020. +Overview +We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +2020 Operational Highlights +During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. Primarily as a result of these unexpected events and the resulting declines in oil prices, we significantly modified our 2020 operational plan. +We began 2020 operating six drilling rigs in the Delaware Basin, as we continued to focus on the exploration, delineation and development of our Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. We had originally planned to operate these six drilling rigs in the Delaware Basin throughout 2020. As a result of the events noted above, however, we released (i) one operated drilling rig from our Wolf asset area late in the first quarter of 2020, (ii) a second operated drilling rig from the Greater Stebbins Area in late April 2020 and (iii) a third operated drilling rig from our Rustler Breaks asset area in late June 2020. We operated three drilling rigs in the Delaware Basin during the remainder of 2020. Two of these rigs operated primarily in the Stateline asset area, and the third rig operated primarily in the Rustler Breaks asset area and in the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area during the second half of 2020. +During the year ended December 31, 2020, we completed and began producing oil and natural gas from 53 gross (45.6 net) operated and 36 gross (2.2 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2020, although we did participate in the drilling and completion of four gross (less than 0.1 net) non-operated Haynesville shale wells that began producing in 2020. +68 +Table of Contents +The vast majority of our 2020 capital expenditures was directed to (i) the delineation and development of our leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin and (iv) the acquisition of additional leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to the installation of pumping units and other facilities on certain of our Eagle Ford shale wells in South Texas and to our participation in several non-operated wells drilled and completed in the Haynesville shale throughout 2020. +Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, an increase of 14%, as compared to 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, for the year ended December 31, 2019. Our average daily oil production in 2020 of 43,526 Bbl of oil per day increased 14% from 38,312 Bbl of oil per day in 2019. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production of 189.9 MMcf per day in 2020 increased 13% from 167.4 MMcf per day in 2019. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production in the Haynesville shale where we had significantly less non-operated activity in 2020 as compared to 2019. Oil production comprised 58% of our total production for each of the years ended December 31, 2020 and December 31, 2019. +For the year ended December 31, 2020, our oil and natural gas revenues were $744.5 million, a decrease of 17% from oil and natural gas revenues of $892.3 million for the year ended December 31, 2019. Our oil revenues decreased 22% to approximately $595.5 million, as compared to $759.8 million for the year ended December 31, 2019. The decrease in oil revenues resulted from a lower weighted average realized oil price of $37.38 per Bbl in 2020, as compared to $54.34 per Bbl in 2019. This decrease was partially offset by the 14% increase in oil production for the year ended December 31, 2020 noted above. Our natural gas revenues increased 12% to approximately $149.0 million, as compared to $132.5 million for the year ended December 31, 2019. The increase in natural gas revenues primarily resulted from the 13% increase in our natural gas production noted above. +We reported a net loss attributable to Matador shareholders of approximately $593.2 million, or ($5.11) per diluted common share, on a GAAP basis for the year ended December 31, 2020, as compared to net income of $87.8 million, or $0.75 per diluted common share, for the year ended December 31, 2019. Adjusted EBITDA for the year ended December 31, 2020 was $519.3 million, as compared to Adjusted EBITDA of $610.8 million for the year ended December 31, 2019. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data—Non-GAAP Financial Measures.” +At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, with a Standardized Measure of $1.58 billion and a PV-10 of $1.66 billion. At December 31, 2019, our estimated total proved oil and natural gas reserves were 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, with a Standardized Measure of $2.03 billion and a PV-10 of $2.25 billion. Our estimated total proved reserves of 270.3 million BOE at December 31, 2020 represented a 7% year-over-year increase, as compared to 252.5 million BOE at December 31, 2019. Our estimated proved oil reserves of 159.9 million Bbl at December 31, 2020 increased 8%, as compared to 148.0 million Bbl at December 31, 2019. Proved oil reserves comprised 59% of our total proved reserves at both December 31, 2020 and December 31, 2019. At December 31, 2020, 46% of our total proved reserves were proved developed reserves, as compared to 42% at December 31, 2019. +Our proved oil and natural gas reserves in the Delaware Basin increased 12% to 261.9 million BOE at December 31, 2020, as compared to 232.8 million BOE at December 31, 2019, primarily as a result of our ongoing delineation and development operations there. At December 31, 2020, approximately 97% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 12% to 156.3 million Bbl at December 31, 2020, as compared to 139.6 million Bbl at December 31, 2019. Proved oil reserves comprised 60% of our Delaware Basin total proved reserves at both December 31, 2020 and December 31, 2019. +At both December 31, 2020 and December 31, 2019, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.” +69 +Table of Contents +2020 Midstream Highlights +Effective October 1, 2020, together with our joint venture partner, Five Point, we completed the successful merger of San Mateo II with and into San Mateo I. San Mateo is owned 51% by us and 49% by Five Point. +San Mateo achieved strong operating results in 2020, highlighted by (i) increased midstream services revenues, (ii) increased produced water handling volumes and (iii) increased oil gathering and transportation volumes, all as compared to 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but, on a quarterly sequential basis, San Mateo’s natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes all increased significantly in the fourth quarter of 2020, as compared to the third quarter, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant, which added an incremental designed inlet capacity of 200 MMcf of natural gas per day to the previously designed inlet capacity of 260 MMcf per day for a total designed inlet capacity of 460 MMcf per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2020, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo also completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). In addition, San Mateo completed and placed in service approximately 19 miles of various diameter crude oil pipelines from certain points of origin in the Greater Stebbins Area to the existing San Mateo interconnect with Plains in Eddy County, New Mexico. At December 31, 2020, San Mateo was gathering or transporting our oil and natural gas production via pipeline in both the Stateline asset area and the Greater Stebbins Area, as well as in the Wolf and Rustler Breaks asset areas. San Mateo was handling our produced water in each of these areas as well. +At December 31, 2020, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 140 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 13 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 335,000 Bbl per day and approximately 120 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +2021 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2021. We plan to operate three contracted drilling rigs in the Delaware Basin for most of the first quarter of 2021. In March 2021, we plan to add a fourth drilling rig and operate four drilling rigs throughout the remainder of 2021. Our 2021 estimated capital expenditure budget consists of $525.0 to $575.0 million for drilling, completing and equipping wells (“D/C/E capital expenditures”) and $20.0 to $30.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2021 capital expenditures. Substantially all of these 2021 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2021 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a higher percentage of longer horizontal wells in 2021, including 98% with anticipated completed lateral lengths of two miles or greater. +70 +Table of Contents +At December 31, 2020, we had $57.9 million in cash (excluding restricted cash) and $214.2 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $700.0 million). Excluding any possible significant acquisitions, we expect to fund our 2021 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2021, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. +We may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position (as we did in 2019 and 2020), as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during 2021. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2021 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2021. The aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. +71 +Table of Contents +Revenues +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2020 2019 2018 +Operating Data: +Revenues (in thousands): (1) +Oil $ 595,507 $ 759,811 $ 635,554 +Natural gas 148,954 132,514 165,146 +Total oil and natural gas revenues 744,461 892,325 800,700 +Third-party midstream services revenues 64,932 59,110 21,920 +Sales of purchased natural gas 41,742 74,769 7,071 +Lease bonus - mineral acreage 4,062 1,711 2,489 +Realized gain on derivatives 38,937 9,482 2,334 +Unrealized (loss) gain on derivatives (32,008) (53,727) 65,085 +Total revenues $ 862,126 $ 983,670 $ 899,599 +Net Production Volumes: (1) +Oil (MBbl) 15,931 13,984 11,141 +Natural gas (Bcf) 69.5 61.1 47.3 +Total oil equivalent (MBOE) (2) +27,514 24,164 19,026 +Average daily production (BOE/d) (2) +75,175 66,203 52,128 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 37.38 $ 54.34 $ 57.04 +Oil, with realized derivatives (per Bbl) $ 39.83 $ 54.98 $ 57.38 +Natural gas, without realized derivatives (per Mcf) $ 2.14 $ 2.17 $ 3.49 +Natural gas, with realized derivatives (per Mcf) $ 2.14 $ 2.18 $ 3.46 +________________ +(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2020 as Compared to Year Ended December 31, 2019 +Oil and natural gas revenues . Our oil and natural gas revenues decreased $147.9 million, or 17%, to $744.5 million for the year ended December 31, 2020, as compared to $892.3 million for the year ended December 31, 2019. Our oil revenues decreased $164.3 million, or 22%, to $595.5 million for the year ended December 31, 2020, as compared to $759.8 million for the year ended December 31, 2019. This decrease in oil revenues resulted from a 31% decrease in the weighted average oil price realized for the year ended December 31, 2020 to $37.38 per Bbl, as compared to $54.34 per Bbl realized for the year ended December 31, 2019. This decrease in our oil revenues was partially offset by the 14% increase in our oil production to 15.9 million Bbl of oil for the year ended December 31, 2020, as compared to 14.0 million Bbl of oil for the year ended December 31, 2019. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production primarily from our properties in the Eagle Ford shale. Our natural gas revenues increased by $16.4 million, or 12%, to $149.0 million for the year ended December 31, 2020, as compared to $132.5 million for the year ended December 31, 2019. The increase in natural gas revenues was primarily attributable to the 14% increase in our natural gas production to 69.5 Bcf for the year ended December 31, 2020, as compared to 61.1 Bcf for the year ended December 31, 2019. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production primarily from our properties in the Haynesville shale. +Third-party midstream services revenues. Our third-party midstream services revenues increased $5.8 million, or 10%, to $64.9 million for the year ended December 31, 2020, as compared to $59.1 million for the year ended December 31, 2019. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $30.1 million for the year ended December 31, 2020, as compared to $27.0 million for the year ended December 31, 2019, (ii) an increase in our third-party oil gathering and transportation revenues to $9.4 million for the year ended December 31, 2020, as compared to $7.2 million for the year ended December 31, 2019, and (iii) an increase in third-party produced water handling revenues to $25.5 million for the year ended December 31, 2020, as compared to $24.9 million for the year ended December 31, 2019. +72 +Table of Contents +Sales of purchased natural gas. Our sales of purchased natural gas decreased $33.0 million, or 44%, to $41.7 million for the year ended December 31, 2020, as compared to $74.8 million for the year ended December 31, 2019. This decrease was primarily the result of a decrease in natural gas volumes sold during the year ended December 31, 2020. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at the Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statement of operations. +Lease bonus - mineral acreage. Our lease bonus - mineral acreage revenues were $4.1 million for the year ended December 31, 2020, as compared to $1.7 million for the year ended December 31, 2019. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests. +Realized gain on derivatives . Our realized net gain on derivatives was $38.9 million for the year ended December 31, 2020, as compared to a realized net gain of approximately $9.5 million for the year ended December 31, 2019. We realized a net gain of $35.1 million related to our oil costless collar, put and swap contracts for the year ended December 31, 2020, resulting primarily from oil prices that were below the floor prices of certain of our oil costless collar contracts and below the strike price of certain of our oil put and swap contracts. We realized a net gain of $3.8 million from our oil basis swap contracts for the year ended December 31, 2020, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized net gains of $8.9 million and $0.5 million from our oil and natural gas costless collar contracts, respectively, for the year ended December 31, 2019, resulting from oil and natural gas prices that were below the floor prices of certain of our oil and natural gas costless collar contracts. We realized a net gain of $0.1 million from our oil basis swap contracts for the year ended December 31, 2019, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized an average gain on our oil derivatives of approximately $2.45 per Bbl of oil produced during the year ended December 31, 2020, as compared to an average gain of $0.64 per Bbl of oil produced during the year ended December 31, 2019. Our total oil volumes hedged for the year ended December 31, 2020 represented 77% of our total oil production, as compared to 59% of our total oil production for the year ended December 31, 2019. Our total natural gas volumes hedged for the year ended December 31, 2020 represented 10% of our total natural gas production, as compared to 12% of our total natural gas production for the year ended December 31, 2019. +Unrealized (loss) gain on derivatives. Our unrealized loss on derivatives was approximately $32.0 million for the year ended December 31, 2020, as compared to an unrealized loss of $53.7 million for the year ended December 31, 2019. During the year ended December 31, 2020, the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts decreased from a net liability of approximately $3.9 million to a net liability of approximately $35.9 million, resulting in an unrealized loss on derivatives of approximately $32.0 million for the year ended December 31, 2020. During the year ended December 31, 2019, the aggregate net fair value of our open oil and natural gas derivative and oil basis swap contracts decreased from a net asset of approximately $49.8 million to a net liability of approximately $3.9 million, resulting in an unrealized loss on derivatives of approximately $53.7 million for the year ended December 31, 2019. +73 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2020 2019 2018 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing $ 93,338 $ 92,273 $ 76,138 +Lease operating 104,953 117,305 92,966 +Plant and other midstream services operating 41,500 36,798 24,609 +Purchased natural gas 32,734 69,398 6,635 +Depletion, depreciation and amortization 361,831 350,540 265,142 +Accretion of asset retirement obligations 1,948 1,822 1,530 +Full-cost ceiling impairment 684,743 — — +General and administrative 62,578 80,054 69,308 +Total expenses 1,383,625 748,190 536,328 +Operating income (521,499) 235,480 363,271 +Other income (expense): +Net loss on asset sales and inventory impairment (2,832) (967) (196) +Interest expense (76,692) (73,873) (41,327) +Prepayment premium on extinguishment of debt — — (31,226) +Other income (expense) 1,864 (2,126) 1,551 +Total other (expense) income (77,660) (76,966) (71,198) +(Loss) income before income taxes (599,159) 158,514 292,073 +Total income tax (benefit) provision (45,599) 35,532 (7,691) +Net income attributable to non-controlling interest in subsidiaries (39,645) (35,205) (25,557) +Net (loss) income attributable to Matador Resources Company shareholders $ (593,205) $ 87,777 $ 274,207 +Expenses per BOE: +Production taxes, transportation and processing $ 3.39 $ 3.82 $ 4.00 +Lease operating $ 3.81 $ 4.85 $ 4.89 +Plant and other midstream services operating $ 1.51 $ 1.52 $ 1.29 +Depletion, depreciation and amortization $ 13.15 $ 14.51 $ 13.94 +General and administrative $ 2.27 $ 3.31 $ 3.64 +Year Ended December 31, 2020 as Compared to Year Ended December 31, 2019 +Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $1.1 million, or 1%, to $93.3 million for the year ended December 31, 2020, as compared to $92.3 million for the year ended December 31, 2019. This increase was primarily attributable to the $11.0 million increase in transportation and processing expenses to $40.0 million for the year ended December 31, 2020, as compared to $29.0 million for the year ended December 31, 2019, primarily resulting from the 14% increase in total oil equivalent production between the respective periods. This increase in transportation and processing expenses was largely offset by a $9.9 million decrease in our production taxes to $53.4 million for the year ended December 31, 2020, as compared to $63.3 million for the year ended December 31, 2019, resulting from the $147.9 million decrease in oil and natural gas revenues for the year ended December 31, 2020, as compared to the year ended December 31, 2019. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 11% to $3.39 per BOE for the year ended December 31, 2020, as compared to $3.82 per BOE for the year ended December 31, 2019, as the 14% increase in total oil equivalent production between the respective periods more than offset the 1% increase in our production taxes, transportation and processing expenses. +Lease operating expenses. Our lease operating expenses decreased $12.4 million, or 11%, to $105.0 million for the year ended December 31, 2020, as compared to $117.3 million for the year ended December 31, 2019. On a unit-of-production basis, our lease operating expenses decreased 21% to $3.81 per BOE for the year ended December 31, 2020, as compared to $4.85 per BOE for the year ended December 31, 2019. These decreases in our lease operating expenses for the year ended December 31, 2020 were primarily attributable to (i) a decrease in produced water disposal expenses of $11.4 million, (ii) a decrease in equipment rental and workover expenses of $4.6 million and (iii) a decrease in ad valorem taxes of $1.1 million. These decreases were partially offset by increases in expenses associated with compressors of $2.4 million, which were attributable to servicing the increased number of wells at December 31, 2020, as compared to December 31, 2019. +74 +Table of Contents +Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $4.7 million, or 13%, to $41.5 million for the year ended December 31, 2020, as compared to $36.8 million for the year ended December 31, 2019. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of $21.8 million for the year ended December 31, 2020, as compared to $18.1 million for the year ended December 31, 2019, and (ii) increased expenses associated with our expanded pipeline operations of $10.0 million for the year ended December 31, 2020, as compared to $7.9 million for the year ended December 31, 2019. These increases were partially offset by decreased expenses associated with operating the Black River Processing Plant of $9.7 million for the year ended December 31, 2020, as compared to $11.0 million for the year ended December 31, 2019. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $11.3 million, or 3%, to $361.8 million for the year ended December 31, 2020, as compared to $350.5 million for the year ended December 31, 2019. This increase was primarily attributable to (i) the 14% increase in total oil equivalent production to 27.5 million BOE for the year ended December 31, 2020, as compared to 24.2 million BOE for the year ended December 31, 2019, and (ii) increased depreciation expenses attributable to our midstream segment of approximately $23.3 million for the year ended December 31, 2020, as compared to $16.1 million for the year ended December 31, 2019. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 9% to $13.15 per BOE for the year ended December 31, 2020, as compared to $14.51 per BOE for the year ended December 31, 2019. On a unit-of-production basis, the decrease was primarily attributable to the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in the second and third quarters of 2020, as well as the 14% increase in total equivalent oil production during 2020. +Full-cost ceiling impairment. Due to the sharp decline in oil and natural gas prices used to estimate proved oil and natural gas reserves in 2020, at June 30, September 30 and December 31, 2020, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an impairment charge of $684.7 million, exclusive of tax effect, to the net capitalized costs. This full-cost ceiling impairment is reflected in our consolidated statement of operations for the year ended December 31, 2020, with the related deferred income tax credit recorded net of a valuation allowance. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the year ended December 31, 2019. +General and administrative. Our general and administrative expenses decreased $17.5 million, or 22%, to $62.6 million for the year ended December 31, 2020, as compared to $80.1 million for the year ended December 31, 2019. Our general and administrative expenses on a unit-of-production basis decreased 31% to $2.27 per BOE for the year ended December 31, 2020, as compared to $3.31 per BOE for the year ended December 31, 2019. These decreases were primarily attributable to cost reductions initially implemented during the three months ended March 31, 2020, including headcount and employee compensation reductions, that were maintained throughout the remainder of 2020. +Interest expense. For the year ended December 31, 2020, we incurred total interest expense of approximately $82.2 million. We capitalized approximately $5.5 million of our interest expense on certain qualifying projects for the year ended December 31, 2020 and expensed the remaining $76.7 million to operations. For the year ended December 31, 2019, we incurred total interest expense of approximately $82.4 million. We capitalized $8.5 million of our interest expense on certain qualifying projects for the year ended December 31, 2019 and expensed the remaining $73.9 million to operations. +Total income tax (benefit) provision. We recorded a total income tax benefit of $45.6 million for the year ended December 31, 2020. As a result of the full-cost ceiling impairments that were recorded during 2020, we recorded a valuation allowance of $110.7 million against our net deferred tax assets for the year ended December 31, 2020, which partially offset the income tax benefit that resulted from our $599.2 million loss before income taxes for the year ended December 31, 2020. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized. Our effective tax rate was 7.6% for the year ended December 31, 2020, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a total income tax provision of $35.5 million for the year ended December 31, 2019. Our effective tax rate was 22.4% for the year ended December 31, 2019, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of permanent differences between book and taxable income and state taxes, primarily in New Mexico. +75 +Table of Contents +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2021 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditures for 2021 primarily through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2021, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. +At December 31, 2020, we had cash totaling $57.9 million and restricted cash totaling $33.5 million, which was associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +At December 31, 2020, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $440.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration (“SBA”) loan. In February 2020, the lenders under the Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. We elected to increase the borrowing commitment from $500.0 million to $700.0 million, and the maximum facility amount remained $1.5 billion. We also added two new banks to our lending group as part of this redetermination process. This February 2020 redetermination constituted the regularly scheduled May 1 redetermination. In October 2020, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $900.0 million. We elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and no changes were made to the terms of the Credit Agreement. This October 2020 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenant noted below). The Credit Agreement matures in October 2023. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 4.00 or less. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2020. Between December 31, 2020 and February 23, 2021, we repaid an additional $10.0 million of borrowings outstanding under the Credit Agreement. +At December 31, 2020, San Mateo had $334.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases to up to $400.0 million, and matures in December 2023. At December 31, 2020, the lender commitments under the San Mateo Credit Facility were $375.0 million (subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2020. Between December 31, 2020 and February 23, 2021, we repaid an additional $11.0 million of borrowings outstanding under the San Mateo Credit Facility. +76 +Table of Contents +During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April, although oil prices began to improve later in the second quarter and throughout the remainder of 2020. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. +Primarily as a result of these unexpected events and the resulting declines in oil prices, we modified our 2020 operational plan. In March 2020, we significantly reduced our capital expenditure budget, including reducing our operated drilling program from six to three drilling rigs by the end of the second quarter of 2020. In addition, we made initial reductions to headcount, employee salaries and lease operating expenses and curtailed or shut in portions of our oil and natural gas production. While we had prepared to make further reductions to headcount, salaries and our capital expenditure budget, we have been able to avoid such reductions to date as a result of realizing greater-than-expected savings from the above changes to our 2020 operational plan, restructuring our hedge portfolio and applying for and receiving an SBA loan through the Paycheck Protection Program. While oil prices have continued to improve into 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains highly uncertain, and we can provide no assurances as to when or to what extent the economic disruptions resulting from COVID-19 and the corresponding decline in oil demand may improve. These economic disruptions have also significantly reduced our ability to access the capital markets on reasonably similar terms as were available in prior periods. +As noted above, on April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately $7.5 million as part of the Paycheck Protection Program. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act and is administered by the SBA. The loan was issued through Iberiabank, which is a lender under the Credit Agreement, matures on the second anniversary of the funding date and bears interest at a fixed rate of 1.00% per a nn um. We used the proceeds of the loan for payroll, including salaries, payroll taxes and employee medical benefits, as permitted by the program. The receipt of the loan allowed us to avoid the planned further reductions to employee headcount and salaries discussed above. The loan is eligible for forgiveness for the portion of the loan proceeds used for payroll costs and other designated operating expenses, provided at least 60% of the loan’s proceeds are used for payroll costs. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2021. We plan to operate three contracted drilling rigs in the Delaware Basin for most of the first quarter of 2021. In March 2021, we plan to add a fourth drilling rig and operate four drilling rigs throughout the remainder of 2021. Our 2021 estimated capital expenditure budget consists of $525.0 to $575.0 million for D/C/E capital expenditures and $20.0 to $30.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2021 capital expenditures. Substantially all of these 2021 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2021 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a higher percentage of longer horizontal wells in 2021, including 98% with anticipated completed lateral lengths of two miles or greater. We have built significant optionality into our drilling program, which allowed us to decrease the number of rigs in 2020 from six to three within a few months and should generally allow us to increase or decrease the number of rigs we operate as necessary based on changing commodity prices and other factors. +We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of acreage and mineral interests, principally in the Delaware Basin, during 2021. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2021 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acreage and mineral acquisitions for 2021. +Our 2021 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital +77 +Table of Contents +expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2021 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2021 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2020. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our cash flows for the years ended December 31, 2020, 2019 and 2018 are presented below. +Year Ended December 31, +2020 2019 2018 +(In thousands) +Net cash provided by operating activities $ 477,582 $ 552,042 $ 608,523 +Net cash used in investing activities (775,666) (903,976) (1,515,253) +Net cash provided by financing activities 324,339 333,078 888,232 +Net change in cash $ 26,255 $ (18,856) $ (18,498) +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ 519,277 $ 610,756 $ 553,223 +__________________ +(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. +Cash Flows Provided by Operating Activities +Net cash provided by operating activities decreased by $74.5 million to $477.6 million for the year ended December 31, 2020, as compared to net cash provided by operating activities of $552.0 million for the year ended December 31, 2019. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $500.7 million for the year ended December 31, 2020 from $586.6 million for the year ended December 31, 2019. This decrease was primarily attributable to significantly lower realized oil prices for the year ended December 31, 2020, as compared to the year ended December 31, 2019. Changes in our operating assets and liabilities between December 31, 2019 and December 31, 2020 resulted in a net increase of approximately $11.4 million in net cash provided by operating activities for the year ended December 31, 2020, as compared to the year ended December 31, 2019. +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. Furthermore, the continued effect of COVID-19 and the corresponding decline in oil demand may also significantly impact the prices we receive for our oil production. These factors are beyond our control and are +78 +Table of Contents +difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities decreased by $128.3 million to $775.7 million for the year ended December 31, 2020 from $904.0 million for the year ended December 31, 2019. This decrease in net cash used in investing activities was primarily attributable to a decrease of $208.3 million in D/C/E capital expenditures as compared to the year ended December 31, 2019, which was partially offset by (i) an increase of approximately $42.3 million in expenditures for midstream support equipment and facilities, which included the construction of the further expansion of the Black River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline infrastructure, (ii) an increase of $22.0 million in expenditures related to acquisition of oil and natural gas properties and (iii) a decrease of $17.1 million in proceeds from sales of assets. Cash used for D/C/E capital expenditures for the year ended December 31, 2020 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin. +Cash Flows Provided by Financing Activities +Net cash provided by financing activities was $324.3 million for the year ended December 31, 2020, as compared to net cash provided by financing activities of $333.1 million for the year ended December 31, 2019. The net cash provided by financing activities for the year ended December 31, 2020 was primarily attributable to net borrowings under our Credit Agreement of $185.0 million, borrowings under the San Mateo Credit Facility of $46.0 million, net contributions related to the formation of San Mateo I and from non-controlling interest owners of less-than-wholly-owned subsidiaries of $88.8 million and receipt of the $7.5 million SBA loan. +See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes. +Guarantor Financial Information +The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2020, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes. +The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor (in thousands). This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities. +Summarized Balance Sheet December 31, 2020 +Assets +Current assets $ 211,930 +Net property and equipment $ 2,605,654 +Other long-term assets $ 68,452 +Liabilities +Current liabilities $ 290,632 +Long-term debt $ 1,480,998 +Other long-term liabilities $ 64,485 +79 +Table of Contents +Year Ended +Summarized Statement of Operations December 31, 2020 +Revenues $ 772,826 +Expenses 1,384,330 +Operating loss $ (611,504) +Other expense $ (68,562) +Tax benefit $ 45,599 +Net loss $ (634,467) +Non-GAAP Financial Measures +We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, prepayment premium on extinguishment of debt and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2020 2019 2018 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net (loss) income attributable to Matador Resources Company shareholders $ (593,205) $ 87,777 $ 274,207 +Net income attributable to non-controlling interest in subsidiaries 39,645 35,205 25,557 +Net (loss) income (553,560) 122,982 299,764 +Interest expense 76,692 73,873 41,327 +Total income tax (benefit) provision (45,599) 35,532 (7,691) +Depletion, depreciation and amortization 361,831 350,540 265,142 +Accretion of asset retirement obligations 1,948 1,822 1,530 +Full-cost ceiling impairment 684,743 — — +Unrealized loss (gain) on derivatives 32,008 53,727 (65,085) +Non-cash stock-based compensation expense 13,625 18,505 17,200 +Net loss (gain) on asset sales and inventory impairment 2,832 967 196 +Prepayment premium on extinguishment of debt — — 31,226 +Consolidated Adjusted EBITDA 574,520 657,948 583,609 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (55,243) (47,192) (30,386) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 519,277 $ 610,756 $ 553,223 +80 +Table of Contents +Year Ended December 31, +2020 2019 2018 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities $ 477,582 $ 552,042 $ 608,523 +Net change in operating assets and liabilities 23,078 34,517 (64,429) +Interest expense, net of non-cash portion 73,860 71,389 39,970 +Current income tax (benefit) provision — — (455) +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (55,243) (47,192) (30,386) +Adjusted EBITDA attributable to Matador Resources Company shareholders 519,277 610,756 553,223 +For the year ended December 31, 2020, we reported a net loss attributable to Matador shareholders of $593.2 million, as compared to net income attributable to Matador shareholders of $87.8 million for the year ended December 31, 2019. This decrease primarily resulted from (i) significantly lower realized oil prices, partially offset by higher oil and natural gas production, for the year ended December 31, 2020, as compared to the year ended December 31, 2019, and (ii) the full-cost ceiling impairment of $684.7 million we recorded for the year ended December 31, 2020. In addition, we recorded an unrealized loss on derivatives of $32.0 million for the year ended December 31, 2020, as compared to an unrealized loss on derivatives of $53.7 million for the year ended December 31, 2019, and we recorded an income tax benefit of $45.6 million for the year ended December 31, 2020, as compared to an income tax provision of $35.5 million for the year ended December 31, 2019. +Adjusted EBITDA, a non-GAAP financial measure, decreased $91.5 million to $519.3 million for the year ended December 31, 2020, as compared to $610.8 million for the year ended December 31, 2019. This decrease was primarily attributable to significantly lower realized oil prices, partially offset by higher oil and natural gas production, for the year ended December 31, 2020, as compared to the year ended December 31, 2019. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2020, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2020. +Payments Due by Period +Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years +(In thousands) +Contractual Obligations: +Borrowings, including letters of credit (1) +$ 836,273 $ — $ 7,470 $ 828,803 $ — +Senior unsecured notes (2) +1,050,000 — — — 1,050,000 +Office leases 22,517 4,040 8,346 8,671 1,460 +Non-operated drilling and other capital commitments (3) +44,560 16,790 18,698 9,072 — +Drilling rig contracts (4) +20,649 17,625 3,024 — — +Asset retirement obligations (5) +38,542 623 3,347 2,038 32,534 +Natural gas transportation, gathering and processing agreements with non-affiliates (6) +630,004 66,837 141,892 143,361 277,914 +Gathering, transportation, processing and disposal agreements with San Mateo (7) +493,839 39,626 88,336 181,612 184,265 +Total contractual cash obligations $ 3,136,384 $ 145,541 $ 271,113 $ 1,173,557 $ 1,546,173 +81 +Table of Contents +__________________ +(1) The amounts included in the table above represent principal maturities only. At December 31, 2020, we had $440.0 million of borrowings outstanding under the Credit Agreement, approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million in borrowings under the SBA loan. The Credit Agreement matures in October 2023. At December 31, 2020 San Mateo had $334.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of 1.90% and 2.15%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at December 31, 2020, the interest expense for such facilities is expected to be approximately $8.5 million and $7.3 million each year until maturity. +(2) The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of December 31, 2020 is expected to be approximately $61.7 million each year until maturity. +(3) At December 31, 2020, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. +(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2020. +(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for gathering, transportation, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments. +(7) In February 2017, in connection with the formation of San Mateo I, we dedicated our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and certain future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. In February 2019, in connection with the formation of San Mateo II, we dedicated acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of OPEC+, the worldwide spread of COVID-19, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. +During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. The sudden decline in oil prices began to improve later in the second quarter of 2020 and throughout the remainder of 2020 and into early 2021. For the year ended December 31, 2020, oil prices averaged $39.34 per Bbl, ranging from a high of $63.27 per Bbl in early January to a low of ($37.63) per Bbl in mid April, based upon the WTI oil futures contract price for the earliest delivery date. +As noted previously in this Annual Report, we significantly modified our 2020 operational plan primarily as a result of these unexpected events and the resulting decline in oil prices. We began 2020 operating six drilling rigs in the Delaware Basin but reduced our operated drilling program from six to three drilling rigs by the end of the second quarter of 2020. We operated three drilling rigs in the Delaware Basin throughout the remainder of 2020. We began 2021 operating three drilling rigs in the Delaware Basin as well, but on February 23, 2021, we announced our plans to add a fourth operated rig in March 2021. We expect to operate four drilling rigs in the Delaware Basin throughout the remainder of 2021. While oil prices have continued to improve into 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains highly uncertain, and we can provide no assurances as to when or to what extent the economic disruptions resulting from COVID-19 and the corresponding decline in oil demand may improve. +We realized a weighted average oil price of $37.38 per Bbl ($39.83 per Bbl including realized gains from oil derivatives) for our oil production for the year ended December 31, 2020, as compared to $54.34 per Bbl ($54.98 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2019. At February 23, 2021, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2020, closing at $61.67 per Bbl, and was higher compared to $51.43 per Bbl on February 24, 2020. Although we have been encouraged by the improved oil price environment in early 2021, we are uncertain that oil prices can remain at these levels. +82 +Table of Contents +Natural gas prices dropped significantly during 2019 and continued to decline during the first half of 2020 before beginning to increase during the middle of the third quarter and continuing to increase during the fourth quarter. For the year ended December 31, 2020, natural gas prices averaged $2.13 per MMBtu, as compared to $2.53 per MMBtu for the year ended December 31, 2019, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2020, natural gas prices began the year at $2.12 per MMBtu and fell to a low of $1.48 per MMBtu at the end of June, before increasing to a high of $3.35 per MMBtu in late October and finishing the year at $2.54 per MMBtu. +We realized a weighted average natural gas price of $2.14 per Mcf (with no realized gains or losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2020, as compared to $2.17 per Mcf ($2.18 per Mcf including realized gains from natural gas derivatives) for the year ended December 31, 2019. As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average natural gas price. At February 23, 2021, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from year-end 2020, closing at $2.88 per MMBtu, and was higher as compared to $1.83 per MMBtu at February 24, 2020. Although we have been encouraged by the improved natural gas price environment, we remain uncertain that natural gas prices can remain at these levels, particularly as we exit the winter heating season. +The prices we receive for oil, natural gas and NGLs heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically, and, as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the leverage ratio covenant under our Credit Agreement. We are uncertain if oil and natural gas prices may rise from their current levels, and in fact, oil and natural gas prices may decrease in future periods. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. +The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2020, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and most of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas. +The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years, but began 2020 slightly positive to the WTI oil price and remained positive through much of the first quarter. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive later in the second quarter and improving throughout the rest of 2020 and into early 2021. It is possible, however, that this differential could turn negative again at certain times in the future. At February 23, 2021, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated oil production for 2021 and 2022. +A portion of our Delaware Basin natural gas production is exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years, including times in April 2019 when natural gas was being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. In early 2020, the Waha basis differential remained significant at about ($1.20) per MMBtu and continued to deteriorate. Natural gas prices at the Waha hub were negative again on certain days in April 2020. The Waha basis differential narrowed during the remainder of the second quarter. During the third quarter of 2020 and, in particular, at the beginning of October 2020, the Waha basis differential widened significantly again, including several days when natural gas was being sold at the Waha hub for negative prices, due to seasonal pipeline maintenance and other factors that reduced capacity out of the Waha hub. These capacity issues have been largely resolved and the Waha basis differential improved during the remainder of 2020 and into early 2021. +The majority of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2020, we have typically realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our +83 +Table of Contents +natural gas production into other markets, e.g., Southern California, to improve our realized natural gas pricing. Further, approximately 18% of our reported natural gas production for the year ended December 31, 2020 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. +We anticipate that the volatility in these oil and natural gas price differentials could persist throughout 2021 or longer as additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets is completed and as the balance between oil supply and demand is restored. We can provide no assurances as to how long these volatile differentials may persist, and as noted above, these price differentials could deteriorate in future periods. Should we experience future periods of negative pricing for natural gas as we have in previous periods, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results of operations. In addition, we have no derivative contracts in place to mitigate our exposure to natural gas price differentials during 2021 or for future periods. +In addition to concerns regarding oil and natural gas prices and basis differentials, the destruction of global oil demand resulting from the decline in economic activity associated with COVID-19, in conjunction with the actions initiated by Saudi Arabia in March 2020 to increase its oil production to world markets, led to a significant oversupply of oil worldwide. On April 10, 2020, the members of OPEC+ (led by Saudi Arabia) reversed course and announced their intentions to reduce oil production significantly for the remainder of 2020 and into 2021 and 2022. The members of OPEC+ have generally adhered to these production cuts, which have contributed to improving oil prices, although OPEC+ may decide to eliminate or reduce such production cuts at a future meeting. It is uncertain to what degree these production cuts may restore the balance between oil supply and demand, and most oil and natural gas industry observers remain skeptical that oil prices can improve further until oil demand improves, most likely as a result of the “re-opening” of the world economy as concerns surrounding COVID-19 begin to subside. +During times of low oil prices, we may elect to shut in or curtail certain volumes of our oil production temporarily rather than sell the oil at further depressed prices. We voluntarily curtailed or shut in portions of our Delaware Basin and Eagle Ford shale oil production in May and June 2020, but these shut-in wells have since been returned to production. As most of our natural gas production in the Delaware Basin is associated with oil production, portions of our natural gas production were also curtailed or shut in. Furthermore, our Delaware Basin production in the first quarter of 2021 has also been impacted by the historically prolonged cold weather conditions experienced in New Mexico and Texas during the middle to latter portions of February. During that time, we estimate that approximately 30% of our average daily oil equivalent production was shut-in, although we continued producing and selling the majority of our oil and natural gas during this period. We have experienced minimal impact to our production volumes due to insufficient storage capacity or damage to refineries downstream of our operations as a result of this winter weather, but if we were to experience such difficulties, we may be required to shut in additional production. When shut-in wells resume production, they may not produce at their previous rates, and we may be required to expend capital to improve their production. We can provide no assurances as to whether additional portions of our production may be shut in or curtailed in the future or how long these periods may persist. +At February 23, 2021, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor also signed an executive order requiring a regulatory framework to ensure reductions of methane emissions. Following that executive order, the NMOCD, NMED and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions that would, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. +84 +Table of Contents +The pause relating to federal oil and natural gas leases in these orders has not restricted activities on existing valid leases. As such, we have continued our operations on federal properties. However, we can provide no assurances that federal regulations will not be adopted that limit our ability to develop our federal properties. Should such actions be taken, they would almost certainly impact our 2021 and future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +In addition, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry, recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2020. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves +85 +Table of Contents +of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related oil and natural gas reserves. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. These instruments typically consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. +In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized gain (loss) on derivatives.” Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under Revenues as “Realized gain (loss) on derivatives.” +86 +Table of Contents +Revenue Recognition +We enter into contracts with customers to sell our oil and natural gas production. Revenue from these contracts is recognized when our performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration we expect to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of our oil marketing contracts transfer physical custody and title at or near the wellhead or a CDP, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on our consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +Our natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of our natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas and transports the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if we elect to take in-kind the natural gas or NGLs, we sell the natural gas or NGLs to a third party. Under the fee-based contracts, we receive NGL and residue gas value, less the fee component, or are invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on our consolidated statements of operations. +We recognize midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. All midstream services revenues related to our working interest are eliminated in consolidation. Since we have a right to payment from our customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, we apply the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +We periodically enter into natural gas purchase transactions with third parties whereby we (i) purchase the third party’s natural gas and subsequently sell the natural gas to other purchasers or (ii) process the third party’s natural gas at the Black River Processing Plant and then purchase, and subsequently sell, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on our consolidated statements of operations as we act as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, we, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of our mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed, and we have no further obligation to the lessee. We record these payments as “Lease bonus - mineral acreage” revenues on our consolidated statements of operations. +Stock-Based Compensation +We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options (all of which were settled in the first quarter of 2020) and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock. +87 +Table of Contents +We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Assumptions are reviewed each time new equity-based option awards are granted and are reviewed quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations or capitalized in accordance with our policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on the date of the grant for awards issued under the 2003 Incentive Plan and the 2012 Incentive Plan and on the trading day prior to the date of grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2020. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” +88 +Table of Contents +Leases +On January 1, 2019, the Company began recording in the consolidated balance sheet certain of the Company’s compressor leases, drilling rig leases and office leases, which were previously considered operating leases and not reported on the Company’s consolidated balance sheets. The present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheet. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheet unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2020, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and Truist Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2020, we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of the costless collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +At December 31, 2020, we had entered into various swap contracts to mitigate our exposure to oil prices, including price differences between NYMEX WTI Cushing and Argus WTI Midland crude oil. When the settlement price is below the fixed price established by one or more of these swaps, we receive from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by one or more of these swaps, we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. +See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2020. Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain +89 +Table of Contents +regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors—Risks Related to Laws and Regulations—The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2020, we had outstanding borrowings of $440.0 million at an interest rate of 1.90% per annum under our Credit Agreement, $1.05 billion in Notes outstanding at a coupon rate of 5.875% per annum and $334.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 2.15% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo is subject to the credit risk of its customers. The inability or failure of our or San Mateo’s significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 23, 2021 were The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and Truist Bank (or affiliates thereof), which are lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2020, 2019 and 2018. Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors—Risks Related to our Operations—The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report beginning on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls +90 +Table of Contents +and procedures were effective as of December 31, 2020 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2020, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2020 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 26, 2021 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 26, 2021 +92 +Table of Contents +Item 9B. Other Information. +Not applicable. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2021 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 3—Ratification of Appointment of KPMG LLP.” +93 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2020 and 2019, Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018. +2. Financial Statement Schedules : All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto. +3. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below. +Item 16. Form 10-K Summary. +None. +94 +Table of Contents +EXHIBIT INDEX +Exhibit +Number Description +2.1 +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).* +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018). +4.3 +First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018). +4.4 +Description of Capital Stock ( incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2019 ) . +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.8† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +95 +Table of Contents +10.10† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.11 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.12 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.13 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.14 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.15 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.16 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +10.17 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.18 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.19 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.20 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.21 +Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016). +10.22 +Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016). +10.23 +Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017) . +10.24† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +96 +Table of Contents +10.25† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.26† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.27† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.28† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.29† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.30† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.31† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.32† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.33† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.34† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.35† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.36† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.37† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.38† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.39† +First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.40† +Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.41 +Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 9, 2018). +10.42 +Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of October 1, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 4, 2018). +97 +Table of Contents +10.43 +Thirteenth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 1, 2018). +10.44† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.45† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.46† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.47† +Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019). +10.48† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.49† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.50† +First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.51† +First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.52 +Fourteenth Amendment to Third Amended and Restated Credit Agreement, dated as of February 27, 2020, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2019). +10.53† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.54† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.55† +S econd Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (filed herewith). +10.56† +Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +98 +Table of Contents +101 The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2020, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +104 Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101). +† Indicates a management contract or compensatory plan or arrangement. +* Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +99 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +February 26, 2021 By: /s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature Title Date +/s/ Joseph Wm. Foran Chairman and Chief Executive Officer February 26, 2021 +Joseph Wm. Foran (Principal Executive Officer) +/s/ David E. Lancaster Executive Vice President and Chief Financial Officer February 26, 2021 +David E. Lancaster (Principal Financial Officer) +/s/ Robert T. Macalik Senior Vice President and Chief Accounting Officer February 26, 2021 +Robert T. Macalik (Principal Accounting Officer) +/s/ Reynald A. Baribault Director February 26, 2021 +Reynald A. Baribault +/s/ R. Gaines Baty Director February 26, 2021 +R. Gaines Baty +/s/ Craig T. Burkert Director February 26, 2021 +Craig T. Burkert +/s/ William M. Byerley Director February 26, 2021 +William M. Byerley +/s/ Monika U. Ehrman Director February 26, 2021 +Monika U. Ehrman +/s/ Julia P. Forrester Rogers Director February 26, 2021 +Julia P. Forrester Rogers +/s/ James M. Howard Director February 26, 2021 +James M. Howard +/s/ Timothy E. Parker Director February 26, 2021 +Timothy E. Parker +/s/ Kenneth L. Stewart Director February 26, 2021 +Kenneth L. Stewart +100 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water. +Bcf . One billion cubic feet of natural gas. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Central delivery point or CDP . The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differential . The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. +Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher +101 +Table of Contents +volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Lateral length . Length of the completed portion of a horizontal well. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or produced water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Organization of Petroleum Exporting Countries or OPEC . An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid. +OPEC+ . A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +102 +Table of Contents +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Prospectivity . Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +103 +Table of Contents +Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Walking rig . A drilling rig that is capable of moving from one drilling location to another a short distance away using a series of hydraulic “feet” built into the substructure of the rig. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +104 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2020, 2019 and 2018 +Index +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2020 and 2019 +F-4 +Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018 +F-5 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018 +F-6 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018 +F- 7 +Notes to Consolidated Financial Statements +F- 8 +Unaudited Supplementary Information +F- 38 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Change in Accounting Principle +As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update 2016‑02, Leases (Topic 842) , and related amendments. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation +As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being +F-2 +Table of Contents +amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. For the year ended December 31, 2020, the Company recorded depletion expense of evaluated oil and natural gas properties of $334.8 million and recorded a ceiling test impairment of $684.7 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company recorded $5.3 billion of gross evaluated oil and natural gas properties as of December 31, 2020. The Company’s internal reserves engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reserves engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company. +We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves, as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reserves engineers as well as the external reserves engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reserves engineers, and (3) the relationship of the external reserves engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reserves engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reserves engineers’ estimate regarding future operating and development costs based on actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and we compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reserves engineers in connection with our evaluation of the Company’s reserves estimates. We analyzed the depletion expense calculation for compliance with industry and regulatory standards, and recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +February 26, 2021 +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2020 2019 +ASSETS +Current assets +Cash $ 57,916 $ 40,024 +Restricted cash 33,467 25,104 +Accounts receivable +Oil and natural gas revenues 85,098 95,228 +Joint interest billings 34,823 67,546 +Other 17,212 26,639 +Derivative instruments 6,727 — +Lease and well equipment inventory 10,584 10,744 +Prepaid expenses and other current assets 15,802 13,207 +Total current assets 261,629 278,492 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated 5,295,931 4,557,265 +Unproved and unevaluated 902,133 1,126,992 +Midstream properties 841,695 643,903 +Other property and equipment 29,561 27,021 +Less accumulated depletion, depreciation and amortization ( 3,701,551 ) ( 2,655,586 ) +Net property and equipment 3,367,769 3,699,595 +Other assets +Derivative instruments 2,570 — +Other long-term assets 55,312 91,589 +Total assets $ 3,687,280 $ 4,069,676 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable $ 13,982 $ 25,230 +Accrued liabilities 119,158 200,695 +Royalties payable 66,049 85,193 +Amounts due to affiliates 4,934 19,606 +Derivative instruments 45,186 1,897 +Advances from joint interest owners 4,191 14,837 +Amounts due to joint ventures — 486 +Other current liabilities 37,436 51,828 +Total current liabilities 290,936 399,772 +Long-term liabilities +Borrowings under Credit Agreement 440,000 255,000 +Borrowings under San Mateo Credit Facility 334,000 288,000 +Senior unsecured notes payable 1,040,998 1,039,416 +Asset retirement obligations 37,919 35,592 +Derivative instruments — 1,984 +Deferred income taxes — 37,329 +Other long-term liabilities 30,402 43,131 +Total long-term liabilities 1,883,319 1,700,452 +Commitments and contingencies (Note 14) +Shareholders’ equity +Common stock — $ 0.01 par value, 160,000,000 shares authorized; 116,847,003 and 116,644,246 shares issued; and 116,844,768 and 116,642,899 shares outstanding, respectively +1,169 1,166 +Additional paid-in capital 2,027,069 1,981,014 +Accumulated deficit ( 741,705 ) ( 148,500 ) +Treasury stock, at cost, 2,235 and 1,347 shares, respectively +( 3 ) ( 26 ) +Total Matador Resources Company shareholders’ equity 1,286,530 1,833,654 +Non-controlling interest in subsidiaries 226,495 135,798 +Total shareholders’ equity 1,513,025 1,969,452 +Total liabilities and shareholders’ equity $ 3,687,280 $ 4,069,676 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +Year Ended December 31, +2020 2019 2018 +Revenues +Oil and natural gas revenues $ 744,461 $ 892,325 $ 800,700 +Third-party midstream services revenues 64,932 59,110 21,920 +Sales of purchased natural gas 41,742 74,769 7,071 +Lease bonus - mineral acreage 4,062 1,711 2,489 +Realized gain on derivatives 38,937 9,482 2,334 +Unrealized (loss) gain on derivatives ( 32,008 ) ( 53,727 ) 65,085 +Total revenues 862,126 983,670 899,599 +Expenses +Production taxes, transportation and processing 93,338 92,273 76,138 +Lease operating 104,953 117,305 92,966 +Plant and other midstream services operating 41,500 36,798 24,609 +Purchased natural gas 32,734 69,398 6,635 +Depletion, depreciation and amortization 361,831 350,540 265,142 +Accretion of asset retirement obligations 1,948 1,822 1,530 +Full-cost ceiling impairment 684,743 — — +General and administrative 62,578 80,054 69,308 +Total expenses 1,383,625 748,190 536,328 +Operating (loss) income ( 521,499 ) 235,480 363,271 +Other income (expense) +Net loss on asset sales and inventory impairment ( 2,832 ) ( 967 ) ( 196 ) +Interest expense ( 76,692 ) ( 73,873 ) ( 41,327 ) +Prepayment premium on extinguishment of debt — — ( 31,226 ) +Other income (expense) 1,864 ( 2,126 ) 1,551 +Total other expense ( 77,660 ) ( 76,966 ) ( 71,198 ) +(Loss) income before income taxes ( 599,159 ) 158,514 292,073 +Income tax provision (benefit) +Current — — ( 455 ) +Deferred ( 45,599 ) 35,532 ( 7,236 ) +Total income tax (benefit) provision ( 45,599 ) 35,532 ( 7,691 ) +Net (loss) income ( 553,560 ) 122,982 299,764 +Net income attributable to non-controlling interest in subsidiaries ( 39,645 ) ( 35,205 ) ( 25,557 ) +Net (loss) income attributable to Matador Resources Company shareholders $ ( 593,205 ) $ 87,777 $ 274,207 +(Loss) earnings per common share +Basic $ ( 5.11 ) $ 0.75 $ 2.41 +Diluted $ ( 5.11 ) $ 0.75 $ 2.41 +Weighted average common shares outstanding +Basic 116,068 116,555 113,580 +Diluted 116,068 117,063 113,691 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2020, 2019 and 2018 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital Accumulated deficit Treasury Stock Non-controlling interest in subsidiaries +Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2018 108,514 $ 1,085 $ 1,666,024 $ ( 510,484 ) 3 $ ( 69 ) $ 1,156,556 $ 100,990 $ 1,257,546 +Issuance of common stock pursuant to employee stock compensation plan 759 8 ( 8 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 81 1 ( 1 ) — — — — — — +Issuance of common stock pursuant to public offering 7,000 70 226,542 — — — 226,612 — 226,612 +Cost to issue equity — — ( 204 ) — — — ( 204 ) — ( 204 ) +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 22,660 — — — 22,660 — 22,660 +Stock options exercised, net of options forfeited in net share settlements 179 2 ( 1,269 ) — — — ( 1,267 ) — ( 1,267 ) +Restricted stock forfeited — — — — 176 ( 4,384 ) ( 4,384 ) — ( 4,384 ) +Contributions related to formation of San Mateo I (see Note 6) — — 14,700 — — — 14,700 — 14,700 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — 85,750 85,750 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 121,520 ) ( 121,520 ) +Cancellation of treasury stock ( 158 ) ( 2 ) ( 4,036 ) — ( 158 ) 4,038 — — — +Current period net income — — — 274,207 — — 274,207 25,557 299,764 +Balance at December 31, 2018 116,375 1,164 1,924,408 ( 236,277 ) 21 ( 415 ) 1,688,880 90,777 1,779,657 +Issuance of common stock pursuant to employee stock compensation plan 240 2 ( 2 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 50 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 23,396 — — — 23,396 — 23,396 +Stock options exercised, net of options forfeited in net share settlements 220 2 3,298 — — — 3,300 — 3,300 +Liability-based stock option awards settled 1 — 11 — — — 11 — 11 +Restricted stock forfeited — — — — 222 ( 3,691 ) ( 3,691 ) — ( 3,691 ) +Contribution related to formation of San Mateo I, net of tax of $ 3.1 million (See Note 6) +— — 11,613 — — — 11,613 — 11,613 +Contribution of property related to formation of San Mateo II (See Note 6) — — ( 506 ) — — — ( 506 ) 506 — +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $ 5.9 million (See Note 6) +— — 22,874 — — — 22,874 48,510 71,384 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 39,200 ) ( 39,200 ) +Cancellation of treasury stock ( 242 ) ( 2 ) ( 4,078 ) — ( 242 ) 4,080 — — — +Current period net income — — — 87,777 — — 87,777 35,205 122,982 +Balance at December 31, 2019 116,644 $ 1,166 $ 1,981,014 $ ( 148,500 ) 1 $ ( 26 ) $ 1,833,654 $ 135,798 $ 1,969,452 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital Accumulated deficit Treasury Stock Non-controlling interest in subsidiaries Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2020 116,644 $ 1,166 $ 1,981,014 $ ( 148,500 ) 1 $ ( 26 ) $ 1,833,654 $ 135,798 $ 1,969,452 +Issuance of common stock pursuant to employee stock compensation plan 244 2 ( 2 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 85 1 ( 1 ) — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 17,452 — — — 17,452 — 17,452 +Stock options exercised, net of options forfeited in net share settlements — — ( 24 ) — — — ( 24 ) — ( 24 ) +Liability-based stock option awards settled in equity 22 — 297 — — — 297 — 297 +Restricted stock forfeited — — — — 149 ( 1,489 ) ( 1,489 ) — ( 1,489 ) +Contribution related to formation of San Mateo I, net of tax of $ 3.1 million (See Note 6) +— — 11,613 — — — 11,613 — 11,613 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $ 4.8 million (See Note 6) +— — 18,232 — — — 18,232 96,622 114,854 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 45,570 ) ( 45,570 ) +Cancellation of treasury stock ( 148 ) — ( 1,512 ) — ( 148 ) 1,512 — — — +Current period net (loss) income — — — ( 593,205 ) — — ( 593,205 ) 39,645 ( 553,560 ) +Balance at December 31, 2020 116,847 $ 1,169 $ 2,027,069 $ ( 741,705 ) 2 $ ( 3 ) $ 1,286,530 $ 226,495 $ 1,513,025 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2020 2019 2018 +Operating activities +Net (loss) income $ ( 553,560 ) $ 122,982 $ 299,764 +Adjustments to reconcile net (loss) income to net cash provided by operating activities +Unrealized loss (gain) on derivatives 32,008 53,727 ( 65,085 ) +Depletion, depreciation and amortization 361,831 350,540 265,142 +Accretion of asset retirement obligations 1,948 1,822 1,530 +Full-cost ceiling impairment 684,743 — — +Stock-based compensation expense 13,625 18,505 17,200 +Prepayment premium on extinguishment of debt — — 31,226 +Deferred income tax (benefit) provision ( 45,599 ) 35,532 ( 7,236 ) +Amortization of debt issuance cost 2,832 2,484 1,357 +Net loss on asset sales and inventory impairment 2,832 967 196 +Changes in operating assets and liabilities +Accounts receivable 53,001 ( 43,261 ) ( 4,934 ) +Lease and well equipment inventory ( 655 ) 4,777 ( 12,176 ) +Prepaid expenses and other current assets ( 3,010 ) ( 4,844 ) ( 1,770 ) +Other long-term assets 1,681 678 3,418 +Accounts payable, accrued liabilities and other current liabilities ( 43,844 ) ( 19,004 ) 68,647 +Royalties payable ( 19,144 ) 20,417 3,418 +Advances from joint interest owners ( 10,646 ) 3,869 8,179 +Other long-term liabilities ( 461 ) 2,851 ( 353 ) +Net cash provided by operating activities 477,582 552,042 608,523 +Investing activities +Drilling, completion and equipping capital expenditures ( 471,087 ) ( 679,395 ) ( 704,947 ) +Acquisition of oil and natural gas properties ( 72,809 ) ( 50,766 ) ( 652,855 ) +Midstream capital expenditures ( 234,359 ) ( 192,035 ) ( 163,222 ) +Expenditures for other property and equipment ( 2,200 ) ( 3,701 ) ( 2,562 ) +Proceeds from sale of assets 4,789 21,921 8,333 +Net cash used in investing activities ( 775,666 ) ( 903,976 ) ( 1,515,253 ) +Financing activities +Repayments of borrowings ( 35,000 ) ( 35,000 ) ( 370,000 ) +Borrowings under Credit Agreement 220,000 250,000 410,000 +Borrowings under San Mateo Credit Facility 46,000 68,000 220,000 +Cost to enter into or amend credit facilities ( 660 ) ( 1,443 ) ( 3,077 ) +Proceeds from issuance of senior unsecured notes — — 1,051,500 +Cost to issue senior unsecured notes — — ( 14,098 ) +Purchase of senior unsecured notes — — ( 605,780 ) +Proceeds from issuance of common stock — — 226,612 +Cost to issue equity — — ( 204 ) +Proceeds from stock options exercised 45 3,300 815 +Contributions related to formation of San Mateo I 14,700 14,700 14,700 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries 119,700 77,330 85,750 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries ( 45,570 ) ( 39,200 ) ( 121,520 ) +Taxes paid related to net share settlement of stock-based compensation ( 1,556 ) ( 3,691 ) ( 6,466 ) +Other 6,680 ( 918 ) — +Net cash provided by financing activities 324,339 333,078 888,232 +Increase (decrease) in cash and restricted cash 26,255 ( 18,856 ) ( 18,498 ) +Cash and restricted cash at beginning of period 65,128 83,984 102,482 +Cash and restricted cash at end of period $ 91,383 $ 65,128 $ 83,984 +Supplemental disclosures of cash flow information (Note 15) +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2020, 2019 and 2018 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint ventures, San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo I”) and San Mateo Midstream II, LLC (collectively with its subsidiaries, “San Mateo II” and, together with San Mateo I, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Effective October 1, 2020, San Mateo II merged with and into San Mateo I. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Reclassifications +Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +Change in Accounting Principles +Leases. During the first quarter of 2019, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and the amendments provided for in ASU 2018-11, Leases (Topic 842) , which require the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that the Company chose to apply. These practical expedients relate to (i) the identification and classification of leases that commenced before the effective date, (ii) the treatment of initial direct costs for leases that commenced before the effective date, (iii) the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset and (iv) the ability to initially apply the new lease standard at the adoption date. During the first quarter of 2019, the Company also +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +adopted ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient, and, as a result, the Company began evaluating land easements that are entered into or modified after December 31, 2018. See Note 4 for additional disclosures related to leases. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (See “—Revenues” below.) In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2020, two significant purchasers accounted for 65 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 57 %) and Exxon Mobil Corporation ( 8 %). For the year ended December 31, 2019, two significant purchasers accounted for 67 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 53 %) and BP America Production Company ( 14 %). For the year ended December 31, 2018, four significant purchasers accounted for 60 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 19 %), BP America Production Company ( 15 %), Occidental Energy Marketing, Inc. ( 14 %), and Western Refining Crude Oil ( 12 %). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2020, 2019 and 2018, approximately 35 %, 31 % and 34 %, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $ 30.0 million, $ 31.1 million and $ 28.3 million of its general and administrative costs into oil and natural gas properties in 2020, 2019 and 2018, respectively. The Company capitalized $ 5.0 million, $ 7.6 million and $ 8.8 million of its interest expense into oil and natural gas properties for the years ended December 31, 2020, 2019 and 2018, respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2020, 2019 and 2018, the Company recorded depletion expense of $ 334.8 million, $ 330.7 million and $ 251.8 million, respectively. Unproved and unevaluated +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10 %, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10 % discount factor is used to determine the present value of future net revenues. For the period from January through December 2020, these average oil and natural gas prices were $ 36.04 per Bbl and $ 1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $ 52.19 per Bbl and $ 2.58 per MMBtu, respectively. For the period from January through December 2018, these average oil and natural gas prices were $ 62.04 per Bbl and $ 3.10 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $ 684.7 million, exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related deferred income tax benefit recorded net of a valuation allowance (see Note 8). +During the years ended December 31, 2019 and 2018, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2019 and 2018. +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Midstream Properties and Other Property and Equipment +Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. The Company capitalized $ 1.8 million, $ 1.8 million and $ 1.6 million of general and administrative costs into midstream properties in 2020, 2019 and 2018, respectively. The Company capitalized $ 0.5 million and $ 0.9 million of interest expense into midstream properties for the years ended December 31, 2020 and 2019. The Company did not capitalize any interest expense into midstream properties for the year ended December 31, 2018. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment. +The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. +Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. +Revenues +The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2020, 2019 and 2018 (in thousands). +Year Ended December 31, +2020 2019 2018 +Revenues from contracts with customers $ 851,135 $ 1,026,204 $ 829,691 +Lease bonus - mineral acreage 4,062 1,711 2,489 +Realized gain on derivatives 38,937 9,482 2,334 +Unrealized (loss) gain on derivatives ( 32,008 ) ( 53,727 ) 65,085 +Total revenues $ 862,126 $ 983,670 $ 899,599 +Year Ended December 31, +2020 2019 2018 +Oil revenues $ 595,507 $ 759,811 $ 635,554 +Natural gas revenues 148,954 132,514 165,146 +Third-party midstream services revenues 64,932 59,110 21,920 +Sales of purchased natural gas 41,742 74,769 7,071 +Total revenues from contracts with customers $ 851,135 $ 1,026,204 $ 829,691 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the Company’s 2003 Stock and Incentive Plan (the “2003 Incentive Plan”) and the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). +The Company’s consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018 include a stock-based compensation (non-cash) expense of $ 13.6 million, $ 18.5 million and $ 17.2 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $ 1.0 million, $ 1.4 million and $ 1.6 million for the years ended December 31, 2020, 2019 and 2018, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +operations for the years ended December 31, 2020 and 2019 also includes $ 4.0 million and $ 3.2 million, respectively, related to liability-based awards expected to be settled in cash. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2020, 2019 and 2018, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2020, 2019 and 2018. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2020, 2019 and 2018 (in thousands, except per share data). +Year Ended December 31, +2020 2019 2018 +Net (loss) income attributable to Matador Resources Company shareholders — numerator $ ( 593,205 ) $ 87,777 $ 274,207 +Weighted average common shares outstanding — denominator +Basic 116,068 116,555 113,580 +Dilutive effect of options and restricted stock units — 508 111 +Diluted weighted average common shares outstanding 116,068 117,063 113,691 +Earnings per common share attributable to Matador Resources Company shareholders +Basic $ ( 5.11 ) $ 0.75 $ 2.41 +Diluted $ ( 5.11 ) $ 0.75 $ 2.41 +A total of 2.5 million, 2.6 million and 1.6 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2020, 2019 and 2018, respectively, because their effects were anti-dilutive. Additionally, 0.7 million restricted shares, which are participating +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +securities, were excluded from the calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2020 were with The Bank of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal) and Truist Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s reserves-based revolving credit agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2020 and 2019 (in thousands). +December 31, +2020 2019 +Oil and natural gas properties +Evaluated (subject to amortization) $ 5,295,931 $ 4,557,265 +Unproved and unevaluated (not subject to amortization) 902,133 1,126,992 +Total oil and natural gas properties 6,198,064 5,684,257 +Accumulated depletion ( 3,623,265 ) ( 2,603,681 ) +Net oil and natural gas properties 2,574,799 3,080,576 +Midstream properties +Midstream equipment and facilities 841,695 643,903 +Accumulated depreciation ( 61,113 ) ( 38,473 ) +Net midstream properties 780,582 605,430 +Other property and equipment +Furniture, fixtures and other equipment 10,591 9,170 +Software 8,116 8,099 +Leasehold improvements 10,854 9,752 +Total other property and equipment 29,561 27,021 +Accumulated depreciation ( 17,173 ) ( 13,432 ) +Net other property and equipment 12,388 13,589 +Net property and equipment $ 3,367,769 $ 3,699,595 +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2020 and the year in which these costs were incurred (in thousands). +Description 2020 2019 2018 2017 and prior Total +Costs incurred for +Property acquisition $ 40,355 $ 40,140 $ 472,577 $ 315,736 $ 868,808 +Exploration wells 576 1,855 169 397 2,997 +Development wells 25,324 4,889 66 49 30,328 +Total $ 66,255 $ 46,884 $ 472,812 $ 316,182 $ 902,133 +Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2020 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +On September 12, 2018, the Company announced the successful acquisition of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $ 387 million in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”). The BLM Acquisition was responsible for a significant portion of the Company’s property acquisition costs in 2018. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $ 33.3 million at December 31, 2020. Of this total, $ 3.0 million was associated with exploration wells and $ 30.3 million was associated with development wells. The Company anticipates that most of the $ 33.3 million associated with these wells in progress at December 31, 2020 will be transferred to the amortization base during 2021. Unproved and unevaluated property costs for exploration and development wells incurred from 2016 through 2019 are costs related to the advanced preparation for wells that we intend to drill in the future. +NOTE 4 — LEASES +The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2020 were 3.09 % and 2.97 % for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2020 and 2019, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of our operating assets, are partially offset by amounts received from other working interest owners in our operated wells. +Year Ended December 31, +2020 2019 +Operating leases +Lease operating $ 12,994 $ 11,877 +Plant and other midstream services 28 110 +General and administrative 3,698 3,209 +Total operating leases (1) +16,720 15,196 +Short-term leases +Lease operating 12,890 10,441 +Plant and other midstream services 5,689 4,983 +General and administrative 47 27 +Total short-term leases (2)(3) +18,626 15,451 +Financing leases +Depreciation of assets 747 976 +Interest on lease liabilities 123 134 +Total financing leases 870 1,110 +Total lease expense $ 36,216 $ 31,757 +_____________________ +(1) Does not include gross payments related to drilling rig leases of $ 33.6 million and $ 28.1 million for the years ended December 31, 2020 and 2019, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2020 and 2019, respectively. +(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. +(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $ 65.3 million and $ 90.3 million for the years ended December 31, 2020 and 2019, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2020 and 2019, respectively. +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2020 and 2019, respectively (in thousands). +December 31, +2020 2019 +Operating leases +Other long-term assets $ 51,528 $ 85,668 +Other current liabilities $ ( 35,716 ) $ ( 50,164 ) +Other long-term liabilities ( 21,598 ) ( 41,459 ) +Total operating lease liabilities $ ( 57,314 ) $ ( 91,623 ) +Financing leases +Other property and equipment, at cost $ 3,673 $ 2,677 +Accumulated depreciation ( 2,134 ) ( 1,324 ) +Net property and equipment $ 1,539 $ 1,353 +Other current liabilities $ ( 621 ) $ ( 799 ) +Other long-term liabilities ( 256 ) ( 524 ) +Total financing lease liabilities $ ( 877 ) $ ( 1,323 ) +The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2020 and 2019, respectively (in thousands). +Year Ended December 31, +2020 2019 +Cash paid related to lease liabilities +Operating cash payments for operating leases $ 15,664 $ 14,941 +Investing cash payments for operating leases $ 33,556 $ 28,034 +Financing cash payments for financing leases $ 790 $ 918 +Right of use assets obtained in exchange for lease obligations entered into during the period +Operating leases $ 12,474 $ 59,740 +Financing leases $ 996 $ 597 +The following table presents the maturities of lease liabilities at December 31, 2020 (in years). +Weighted-Average Remaining Lease Term December 31, 2020 +Operating leases 2.6 +Financing leases 2.0 +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 4 — LEASES — Continued +The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2020 (in thousands). +December 31, 2020 +Operating Leases Financing Leases +2021 $ 35,716 $ 621 +2022 9,978 308 +2023 4,289 102 +2024 4,207 — +2025 4,285 — +Thereafter 1,649 — +Total lease payments 60,124 1,031 +Less imputed interest ( 2,810 ) ( 154 ) +Total lease obligations 57,314 877 +Less current obligations ( 35,716 ) ( 621 ) +Long-term lease obligations $ 21,598 $ 256 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS +The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2020 and 2019 (in thousands). +Year Ended December 31, +2020 2019 +Beginning asset retirement obligations $ 36,211 $ 31,086 +Liabilities incurred during period 2,548 3,811 +Liabilities settled during period ( 290 ) ( 155 ) +Revisions in estimated cash flows ( 1,875 ) 1,792 +Divestitures during the period — ( 2,145 ) +Accretion expense 1,948 1,822 +Ending asset retirement obligations 38,542 36,211 +Less: current asset retirement obligations (1) +( 623 ) ( 619 ) +Long-term asset retirement obligations $ 37,919 $ 35,592 +__________________ +(1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2020 and 2019. +F-19 +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES +Joint Ventures +On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo I, a joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). The midstream assets contributed to San Mateo I include (i) the Black River Processing Plant (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo I’s other assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of San Mateo. +The Company and Five Point own 51 % and 49 % of San Mateo I, respectively. Five Point provided initial cash consideration of $ 176.4 million to San Mateo I in exchange for its 49 % interest. Approximately $ 171.5 million of this cash contribution by Five Point was distributed by San Mateo I to the Company as a special distribution. The Company had the potential to earn up to $ 73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 23, 2021, the Company had earned $ 58.8 million of the potential $ 73.5 million in performance incentives. Through February 23, 2021, Five Point had paid $ 14.7 million in performance incentives in each of the first quarters of 2018, 2019 and 2020, and the Company expects Five Point to pay an additional $ 14.7 million in performance incentives in the first quarter of 2021. The Company may earn up to the remaining $ 14.7 million in performance incentives over the next two years . These performance incentives are recorded as additional contributions related to the formation of San Mateo I as they are received. The Company contributed the Delaware Midstream Assets and $ 5.1 million in cash to San Mateo I in exchange for its 51 % interest. +The Company dedicated its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas to San Mateo I pursuant to 15 -year, fixed-fee oil, natural gas and produced water gathering and produced water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo I pursuant to a 15 -year, fixed-fee natural gas processing agreement (see Note 14). +On February 25, 2019, the Company announced the formation of San Mateo II, a strategic joint venture with Five Point designed to expand the Company’s midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II was owned 51 % by the Company and 49 % by Five Point. In addition, Five Point committed to pay $ 125.0 million of the first $ 150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and the Stateline asset area. During the year ended December 31, 2020, the $ 150.0 million threshold for capital expenditures was reached, and additional capital expenditures were the responsibility of Matador and Five Point based on each company’s proportionate interest. During the year ended December 31, 2020, the Company contributed $ 59.7 million and Five Point contributed $ 105.0 million of cash to San Mateo II, of which $ 23.1 million was paid to carry Matador’s proportionate interest. The portion of the amount contributed by Five Point to carry Matador’s proportionate interest was recorded in “Additional paid-in capital” in the Company’s consolidated balance sheets at December 31, 2020, net of the $ 4.8 million deferred tax impact to Matador related to this equity contribution. During the year ended December 31, 2019, the Company contributed $ 15.5 million of cash, and Five Point contributed $ 69.0 million of cash, of which $ 28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was therefore recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $ 5.9 million deferred tax impact to Matador related to this equity contribution. Upon formation of San Mateo II, in the first quarter of 2019, the Company also contributed $ 1.0 million of property to San Mateo II. In addition, the Company has the ability to earn up to $ 150.0 million in deferred performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. +In connection with the formation of San Mateo II, the Company dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements (see Note 14). +Effective October 1, 2020, San Mateo II merged with and into San Mateo I. San Mateo is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo being accounted for as a non-controlling interest. +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +Divestitures +During 2020 and 2019, we converted approximately $ 4.8 million and $ 21.9 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin. +NOTE 7 — DEBT +At December 31, 2020, the Company had (i) $ 1.05 billion of outstanding senior notes due 2026, (ii) $ 440.0 million in borrowings outstanding under its reserves-based revolving credit facility, (iii) approximately $ 45.8 million in outstanding letters of credit issued pursuant to its revolving credit facility and (iv) $ 7.5 million outstanding under an unsecured U.S. Small Business Administration loan. +At December 31, 2020, San Mateo had $ 334.0 million in borrowings outstanding under its revolving credit facility and approximately $ 9.0 million in outstanding letters of credit issued pursuant to its revolving credit facility. +Credit Agreements +MRC Energy Company +On September 28, 2012, the Company amended and restated its revolving credit facility with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company, a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80 % of the Company’s proved oil and natural gas properties and by the equity interests of certain of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. The Credit Agreement matures October 31, 2023. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. +In February 2020, the lenders under the Credit Agreement completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $ 900.0 million. The Company elected to increase the borrowing commitment from $ 500.0 million to $ 700.0 million, and the maximum facility amount remained $ 1.5 billion. The Company also added two new banks to the lending group as part of this redetermination process. This February 2020 redetermination constituted the regularly scheduled May 1 redetermination. In October 2020, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was reaffirmed at $ 900.0 million. The Company elected to keep the borrowing commitment at $ 700.0 million, the maximum facility amount remained $ 1.5 billion and no changes were made to the terms of the Credit Agreement. This October 2020 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenant noted below). +In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +Total deferred loan costs were $ 1.7 million at December 31, 2020, and these costs are being amortized over the term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 1.90 % at December 31, 2020. At December 31, 2020, the Company had $ 440.0 million in borrowings outstanding under the Credit Agreement and approximately $ 45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. Between December 31, +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 7 — DEBT — Continued +2020 and February 23, 2021, the Company repaid an additional $ 10.0 million of borrowings outstanding under the Credit Agreement. +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50 %, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0 % plus, in each case, an amount ranging from 0.25 % to 1.25 % per annum depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.25 % to 2.25 % per annum depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. If the Company has outstanding borrowings under the Credit Agreement and interest rates increase, so will the Company’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375 % to 0.50 % per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $ 50 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 4.00 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of the Company’s assets; +• enter into commodity hedging agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and +• take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving the Company or its subsidiaries; and +• a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2020. +San Mateo Midstream, LLC +On December 19, 2018, San Mateo I entered into a $ 250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and including all lenders party to the Credit Agreement at that time. The San Mateo Credit Facility, which matures December 19, 2023, includes an accordion feature, which provides for potential increases to up to $ 400.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 7 — DEBT — Continued +property. At December 31, 2020, the lender commitments under the San Mateo Credit Facility were $ 375.0 million (subject to San Mateo’s compliance with the covenants noted below). +Total deferred loan costs were $ 2.1 million at December 31, 2020, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 2.15 % at December 31, 2020. At December 31, 2020, San Mateo had $ 334.0 million in borrowings outstanding under the San Mateo Credit Facility and $ 9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between December 31, 2020 and February 23, 2021, San Mateo repaid $ 11.0 million in borrowings outstanding under the San Mateo Credit Facility. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50 %, and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0 % plus, in each case, an amount ranging from 0.50 % to 1.50 % per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 1.50 % to 2.50 % per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +A commitment fee of 0.30 % to 0.50 % per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of San Mateo’s assets; +• enter into hedging agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and +• issue equity interests in San Mateo or its subsidiaries. +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving San Mateo or its subsidiaries; and +• a change of control, as defined in the San Mateo Credit Facility. +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 7 — DEBT — Continued +The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2020. +Senior Unsecured Notes +On April 14, 2015, Matador issued $ 400.0 million of 6.875 % senior notes due 2023 (the “Original 2023 Notes”) in a private placement at par value. The Company received net proceeds of approximately $ 391.0 million, after deducting the initial purchasers’ discounts and offering expenses. The Original 2023 Notes were later exchanged for a like principal amount of 6.875 % senior notes due 2023 (the “2023 Exchange Notes”) that were registered under the Securities Act of 1933, as amended (the “Securities Act”), at par value. On December 9, 2016, Matador issued $ 175.0 million of 6.875 % senior notes due 2023 (the “Additional 2023 Notes”) in a private placement, at 105.5 % of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5 %. The Company received net proceeds of approximately $ 181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional 2023 Notes. The Additional 2023 Notes were later exchanged for a like principal amount of 6.875 % senior notes due 2023 that were registered under the Securities Act (together with the 2023 Exchange Notes, the “2023 Notes”). +On August 21, 2018, the Company issued $ 750.0 million of 5.875 % senior notes due 2026 (the “Original 2026 Notes”) in a private placement at par value (the “2026 Notes Offering”). The Company received net proceeds of approximately $ 740.0 million, after deducting the initial purchasers’ discounts and offering expenses. In conjunction with the 2026 Notes Offering, in August and September 2018, respectively, the Company completed a tender offer to purchase for cash and subsequent redemption of all of the 2023 Notes (the “2023 Notes Tender Offer and Redemption”). The Company used a portion of the net proceeds from the 2026 Notes Offering to fund the 2023 Notes Tender Offer and Redemption. In connection with the 2023 Notes Tender Offer and Redemption, the Company incurred a loss of $ 31.2 million, including total payments of $ 30.4 million to holders of the 2023 Notes as a result of the tender premium and the required 105.156 % redemption price payable pursuant to the 2023 Notes indenture. +On October 4, 2018, the Company issued an additional $ 300.0 million of 5.875 % senior notes due 2026 (the “Additional 2026 Notes”). The Additional 2026 Notes were issued pursuant to, and are governed by, the same indenture governing the Original 2026 Notes (the “Indenture”). The Additional 2026 Notes were issued at 100.5 % of par, plus accrued interest from August 21, 2018. The Company received net proceeds from this offering of approximately $ 297.3 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest from August 21, 2018 paid by the initial purchasers of the Additional 2026 Notes. The proceeds from this offering were used to repay a portion of the outstanding borrowings under the Credit Agreement, which were incurred in connection with the BLM Acquisition. +In December 2018, the Company exchanged substantially all of the Original 2026 Notes and Additional 2026 Notes for a like principal amount of 5.875 % senior notes due 2026 that were registered under the Securities Act (the “Notes”). The terms of the Notes are substantially the same as the terms of the Original 2026 Notes and Additional 2026 Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original 2026 Notes and Additional 2026 Notes do not apply to the Notes. The Notes will mature September 15, 2026, and interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries (as defined in the Indenture) or Guarantors of the Notes. +On or after September 15, 2021, the Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: +Year Redemption Price +2021 104.406 % +2022 102.938 % +2023 101.469 % +2024 and thereafter 100.000 % +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 7 — DEBT — Continued +At any time prior to September 15, 2021, the Company may redeem up to 35 % of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 105.875 % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, provided that (i) at least 65 % in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by the Company and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. +In addition, at any time prior to September 15, 2021, the Company may redeem all or part of the Notes at a redemption price equal to the sum of: +(i) the principal amount thereof, plus +(ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at September 15, 2021 plus (2) any required interest payments due on such Notes through September 15, 2021, discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus +(iii) accrued and unpaid interest, if any, to the redemption date. +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• default for 30 days in the payment when due of interest on the Notes; +• default in the payment when due of the principal of, or premium, if any, on the Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 50.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 50.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 7 — DEBT — Continued +The outstanding borrowings of $ 440.0 million at December 31, 2020 under the Credit Agreement mature on October 31, 2023. The outstanding borrowings of $ 334.0 million at December 31, 2020 under the San Mateo Credit Facility mature on December 19, 2023. The $ 1.05 billion of outstanding Notes at December 31, 2020 mature on September 15, 2026. +NOTE 8 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2020 and 2019 is as follows (in thousands). +December 31, +2020 2019 +Deferred tax assets +Net operating loss carryforwards $ 122,952 $ 119,900 +Unrealized loss on derivatives 8,997 960 +Percentage depletion carryover 1,462 1,467 +Compensation 10,405 13,690 +Lease liabilities 9,380 17,107 +Other 8,334 8,139 +Total deferred tax assets 161,530 161,263 +Valuation allowance on deferred tax assets ( 110,681 ) ( 6,736 ) +Total deferred tax assets, net of valuation allowance 50,849 154,527 +Deferred tax liabilities +Property and equipment ( 11,879 ) ( 151,504 ) +Less than wholly-owned subsidiaries ( 26,564 ) ( 20,604 ) +Lease right of use assets ( 9,380 ) ( 17,107 ) +Other ( 2,684 ) ( 2,641 ) +Total deferred tax liabilities ( 50,507 ) ( 191,856 ) +Net deferred tax assets (liabilities) $ 342 $ ( 37,329 ) +At December 31, 2020, the Company had net operating loss carryforwards of $ 541.9 million for federal income tax purposes and $ 161.0 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027. +As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the year ended December 31, 2020, the Company recorded an impairment charge of $ 684.7 million, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. Due to these impairment charges, at December 31, 2020, the Company’s deferred tax assets exceeded its deferred tax liabilities. As a result, the Company established a valuation allowance against most of the deferred tax assets. The remaining net deferred tax asset at December 31, 2020 relates to state taxes, for which the deferred taxes were determined to be more likely than not to be utilized. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 8 — INCOME TAXES — Continued +The current income tax provision and the deferred income tax provision for the years ended December 31, 2020, 2019 and 2018 were comprised of the following (in thousands). +Year Ended December 31, +2020 2019 2018 +Current income tax (benefit) provision +Federal income tax $ — $ — $ ( 455 ) +State income tax — — — +Net current income tax benefit $ — $ — $ ( 455 ) +Deferred income tax (benefit) provision +Federal income tax $ ( 25,675 ) $ 29,171 $ ( 20,457 ) +State income tax ( 19,924 ) 6,361 13,221 +Net deferred income tax (benefit) provision $ ( 45,599 ) $ 35,532 $ ( 7,236 ) +Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2020, 2019 and 2018 is as follows (in thousands). +Year Ended December 31, +2020 2019 2018 +Federal tax (benefit) expense at statutory rate (1) +$ ( 125,823 ) $ 33,441 $ 61,543 +State income tax ( 20,607 ) 6,141 16,181 +Permanent differences ( 3,114 ) ( 4,267 ) ( 2,488 ) +AMT credit refundable — — 455 +Change in federal valuation allowance 103,262 — ( 80,003 ) +Change in state valuation allowance 683 217 ( 2,924 ) +Net deferred income tax (benefit) provision ( 45,599 ) 35,532 ( 7,236 ) +Net current income tax benefit — — ( 455 ) +Total income tax (benefit) provision $ ( 45,599 ) $ 35,532 $ ( 7,691 ) +__________________ +(1) The statutory federal tax rate was 21% for the years ended December 31, 2020, 2019 and 2018. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2017. The earliest tax year open for examination for the State of Texas tax return is 2016. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2020, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +NOTE 9 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2003, the Company’s Board of Directors and shareholders approved the 2003 Incentive Plan. The 2003 Incentive Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. In 2012, the Board of Directors adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. +In 2019, the Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of December 31, 2020, the 2019 Incentive Plan provided for a maximum of 1,940,386 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2003 Incentive Plan or the 2012 Incentive Plan, but both plans will remain in place until all awards outstanding under such plans have been settled. As of December 31, 2020, no awards remained outstanding under the 2003 Incentive Plan. +The 2012 Incentive Plan and the 2019 Incentive Plan are administered by the independent members of the Board of Directors, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. +During the year ended December 31, 2019, the Company began granting both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. +Stock Options +Under the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted and are outstanding to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or 10 years. The 2012 Incentive Plan defines fair market value as the closing price of Matador’s common stock on the date of grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing price of Matador’s common stock on the trading day prior to the date of grant. All remaining option awards granted under the 2003 Incentive Plan were settled in the first quarter of 2020. +The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan and the 2019 Incentive Plan were estimated using the following weighted average assumptions during the years ended December 31, 2019 and 2018. The Company did not issue stock option awards during the year ended December 31, 2020. +2019 2018 +Stock option pricing model Black Scholes Merton Black Scholes Merton +Expected option life 4.00 years 4.00 years +Risk-free interest rate 1.46 % 2.51 % +Volatility 48.52 % 45.17 % +Dividend yield — % — % +Estimated forfeiture rate 4.43 % 2.24 % +Weighted average fair value of stock option awards granted during the year $ 5.04 $ 12.64 +The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2020 under the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2019 3,260 $ 22.64 +Options granted — $ — +Options exercised ( 65 ) $ 9.00 +Options forfeited ( 20 ) $ 15.83 +Options expired ( 702 ) $ 22.53 +Options outstanding at December 31, 2020 2,473 $ 23.08 +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +Options outstanding at +December 31, 2020 Options exercisable at +December 31, 2020 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$ 13.22 - $ 15.40 +914 2.71 $ 14.88 568 $ 14.92 +$ 20.01 - $ 22.70 +40 0.55 $ 22.07 40 $ 22.07 +$ 25.31 - $ 29.68 +1,519 2.49 $ 28.05 1,334 $ 27.82 +At December 31, 2020, there was no aggregate intrinsic value for both outstanding and exercisable options, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2020 was 2.10 years. +The total intrinsic value of options exercised during the years ended December 31, 2020, 2019 and 2018 was $ 0.3 million, $ 0.8 million and $ 7.0 million, respectively. The tax related benefit realized from the exercise of stock options totaled $ 1.4 million, $ 2.8 million and $ 5.7 million for the years ended December 31, 2020, 2019 and 2018, respectively. +At December 31, 2020, the total remaining unrecognized compensation expense related to unvested stock options was approximately $ 1.8 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.39 years. +The fair value of options vested during 2020, 2019 and 2018 was $ 6.7 million, $ 9.7 million and $ 11.8 million, respectively. +Service-Based Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2018 were service-based awards and vest over the service period, which is one to four years . Restricted stock and restricted stock units granted in 2020 and 2019 were either service-based awards, which will settle in cash or equity, or performance-based restricted stock units, which vest in an amount between zero and 200 % of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2022 and December 31, 2021, respectively, as compared to a designated peer group, and will be settled in stock. All restricted stock and restricted stock unit awards outstanding at December 31, 2020 were granted under the 2012 Incentive Plan or the 2019 Incentive Plan. +Equity-Based +A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2020 is presented below (in thousands, except fair value). +Restricted Stock Restricted Stock Units +Service Based Service Based Performance Based +Non-vested restricted stock and +restricted stock units Shares Weighted +average +fair +value Shares Weighted +average +fair +value Shares Weighted +average +fair +value +Non-vested at December 31, 2019 897 $ 26.19 92 $ 16.06 428 $ 20.00 +Granted 243 $ 10.31 83 $ 8.85 641 $ 1.74 +Vested ( 441 ) $ 27.03 ( 92 ) $ 16.06 — $ — +Forfeited ( 17 ) $ 24.69 ( 8 ) $ 8.85 — $ — +Non-vested at December 31, 2020 682 $ 20.01 75 $ 8.85 1,069 $ 9.05 +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +Liability-Based +A summary of the non-vested liability-based restricted stock units as of December 31, 2020 is presented below (in thousands, except fair value). +Non-vested +restricted stock units Shares +Non-vested at December 31, 2019 686 +Granted 868 +Vested ( 226 ) +Forfeited ( 9 ) +Non-vested at December 31, 2020 1,319 +At December 31, 2020, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ 38.7 million, of which $ 16.3 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. +At December 31, 2020, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $ 20.4 million, of which $ 11.1 million is expected to be settled in cash, and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.72 years. +The fair value of restricted stock and restricted stock units vested during 2020, 2019 and 2018 was $ 8.4 million, $ 13.6 million and $ 13.0 million, respectively. +Summary +During the years ended December 31, 2020, 2019 and 2018, the total expense attributable to stock options was $ 3.4 million, $ 6.4 million and $ 6.3 million, respectively. At December 31, 2020, 2019 and 2018, the Company recorded decreases of $ 0.3 million and $ 0.1 million to current liabilities and a decrease of $ 1.1 million to long-term liabilities, respectively, related to its outstanding liability-based stock options. The Company settled 226,363 liability-based awards for $ 2.4 million in cash for the year ended December 31, 2020. The Company did not settle any liability awards for the years ended December 31, 2019 and 2018. During the years ended December 31, 2020, 2019 and 2018, the total expense attributable to restricted stock and restricted stock units was $ 17.7 million, $ 20.2 million and $ 15.3 million, respectively. During the years ended December 31, 2020, 2019 and 2018, the Company capitalized $ 3.6 million, $ 5.0 million and $ 4.4 million, respectively, related to stock-based compensation and expensed the remaining $ 17.6 million, $ 21.6 million and $ 17.2 million, respectively. +The total tax benefit recognized for all stock-based compensation was $ 4.5 million, $ 5.6 million and $ 4.8 million for the years ended December 31, 2020, 2019 and 2018, respectively. +NOTE 10 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3 % of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $ 1.4 million, $ 1.4 million and $ 1.1 million in 2020, 2019 and 2018, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $ 1.8 million, $ 1.7 million and $ 1.4 million in 2020, 2019 and 2018, respectively. The Company made no additional contributions in any reporting period presented. +NOTE 11 — EQUITY +Common Stock +On May 17, 2018, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $ 0.2 million, the Company received net proceeds of approximately $ 226.4 million. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 11 — EQUITY — Continued +Treasury Stock +On October 22, 2020, October 24, 2019 and October 25, 2018, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2020, 2019 and 2018, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2020, 2019 and 2018 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2020, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling and fixed price for the swaps. At December 31, 2020, each contract was set to expire at varying times during 2021 and 2022. The Company had no open contracts associated with NGL prices at December 31, 2020. +The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2020. +Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or +$/MMBtu) Weighted Average Price Ceiling ($/Bbl or +$/MMBtu) Fair Value of Asset (Liability) (thousands) +Commodity Calculation Period +Oil 01/01/2021 - 12/31/2021 5,880,000 $ 37.19 $ 48.09 $ ( 18,734 ) +Natural Gas 01/01/2021 - 12/31/2021 47,000,000 $ 2.46 $ 3.68 5,475 +Natural Gas 01/01/2022 - 03/31/2022 3,000,000 $ 2.60 $ 4.22 220 +Total open costless collar contracts $ ( 13,039 ) +The following is a summary of the Company’s open swap contracts for oil at December 31, 2020. +Commodity Calculation Period Notional Quantity (Bbl) Fixed Price +($/Bbl) Fair Value of Asset (Liability) (thousands) +Oil 01/01/2021 - 12/31/2021 2,040,000 $ 35.26 $ ( 26,451 ) +Total open swap contracts $ ( 26,451 ) +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2020. +Commodity Calculation Period Notional Quantity (Bbl) Fixed Price +($/Bbl) Fair Value of Asset (Liability) (thousands) +Oil Basis Swaps 01/01/2021 - 12/31/2021 8,400,000 $ 0.87 $ 1,229 +Oil Basis Swaps 01/01/2022 - 12/31/2022 5,520,000 $ 0.95 2,372 +Total open basis swap contracts $ 3,601 +At December 31, 2020, the Company had an aggregate net liability value for open derivative financial instruments of $ 35.9 million. +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2020 and December 31, 2019 (in thousands). +Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets +December 31, 2020 +Current assets $ 382,328 $ ( 375,601 ) $ 6,727 +Other assets 150,194 ( 147,624 ) 2,570 +Current liabilities ( 420,787 ) 375,601 ( 45,186 ) +Long-term liabilities ( 147,624 ) 147,624 — +Total $ ( 35,889 ) $ — $ ( 35,889 ) +December 31, 2019 +Current assets $ 442,291 $ ( 442,291 ) $ — +Other assets 280,397 ( 280,397 ) — +Current liabilities ( 444,188 ) 442,291 ( 1,897 ) +Long-term liabilities ( 282,381 ) 280,397 ( 1,984 ) +Total $ ( 3,881 ) $ — $ ( 3,881 ) +The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). +Year Ended December 31, +Type of Instrument Location in Statements of Operations 2020 2019 2018 +Derivative Instrument +Oil Revenues: Realized gain on derivatives $ 38,937 $ 9,026 $ 3,741 +Natural Gas Revenues: Realized gain (loss) on derivatives — 456 ( 1,407 ) +Realized gain on derivatives 38,937 9,482 2,334 +Oil Revenues: Unrealized (loss) gain on derivatives ( 37,703 ) ( 53,443 ) 65,991 +Natural Gas Revenues: Unrealized gain (loss) on derivatives 5,695 ( 284 ) ( 906 ) +Unrealized (loss) gain on derivatives ( 32,008 ) ( 53,727 ) 65,085 +Total $ 6,929 $ ( 44,245 ) $ 67,419 +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 13 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2020 and 2019 (in thousands). +Fair Value Measurements at +December 31, 2020 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Oil derivatives and basis swaps $ — $ ( 41,584 ) $ — $ ( 41,584 ) +Natural gas derivatives — 5,695 — 5,695 +Total $ — $ ( 35,889 ) $ — $ ( 35,889 ) +Fair Value Measurements at +December 31, 2019 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Oil derivatives and basis swaps $ — $ ( 3,881 ) $ — $ ( 3,881 ) +Total $ — $ ( 3,881 ) $ — $ ( 3,881 ) +Additional disclosures related to derivative financial instruments are provided in Note 12. +Other Fair Value Measurements +At December 31, 2020 and 2019, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximated their fair values due to their short-term maturities. +At December 31, 2020 and 2019, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2020 and 2019, the fair value of the Notes was $ 1.03 billion and $ 1.06 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 13 — FAIR VALUE MEASUREMENTS — Continued +the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2020 and 2019. +NOTE 14 — COMMITMENTS AND CONTINGENCIES +Processing, Transportation and Produced Water Disposal Commitments +Firm Commitments +From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $ 46.0 million and $ 28.7 million for deliveries under these agreements during the years ended December 31, 2020 and 2019, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2020, the total deficiencies required to be paid by the Company under these agreements would be approximately $ 523.1 million, in addition to the future commitments and the San Mateo commitments described below. +Future Commitments +In October 2019, the Company entered into a 15 -year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. The agreement began when the counterparty’s pipeline was placed in service, which occurred during the first quarter of 2021. Now that the pipeline has been placed in service, the Company owes the fees to transport the committed volume whether or not the committed volume is transported through the counterparty’s pipeline. The minimum contractual obligation was approximately $ 106.9 million when the pipeline was placed in service. +San Mateo Commitments +In February 2017, the Company dedicated its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15 -year, fixed-fee oil, natural gas and produced water gathering and produced water disposal agreements with subsidiaries of San Mateo I. In addition, the Company dedicated its current and certain future leasehold interests in the Rustler Breaks asset area pursuant to a 15 -year, fixed-fee natural gas processing agreement (collectively with the gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2020 was approximately $ 153.5 million. +In connection with the February 2019 formation of San Mateo II, the Company dedicated to San Mateo acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements (collectively, the “San Mateo II Operational Agreements”). San Mateo provides the Company with firm service under each of the San Mateo II Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the San Mateo II Operational Agreements at December 31, 2020 was approximately $ 340.3 million. +In June 2019, a subsidiary of San Mateo entered into an agreement with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion was placed in service in the third quarter of 2020. San Mateo’s total commitments under this agreement were $ 81.3 million. San Mateo paid approximately $ 41.2 million under this agreement during the year ended December 31, 2020. As of December 31, 2020, there were no remaining obligations under this agreement. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $ 20.6 million at December 31, 2020. +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 14 — COMMITMENTS AND CONTINGENCIES — Continued +At December 31, 2020, the Company had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these operated and non-operated wells were approximately $ 44.6 million at December 31, 2020. The Company expects these costs to be incurred within the next three to five years . +Legal Proceedings +The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +NOTE 15 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2020 and 2019 (in thousands). +December 31, +2020 2019 +Accrued evaluated and unproved and unevaluated property costs $ 44,012 $ 72,376 +Accrued midstream properties costs 12,776 46,402 +Accrued lease operating expenses 24,276 18,223 +Accrued interest on debt 18,315 18,569 +Accrued asset retirement obligations 623 619 +Accrued partners’ share of joint interest charges 7,407 14,322 +Accrued payable related to purchased natural gas 418 17,806 +Other 11,331 12,378 +Total accrued liabilities $ 119,158 $ 200,695 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2020, 2019 and 2018 (in thousands). +Year Ended December 31, +2020 2019 2018 +Cash paid for interest expense, net of amounts capitalized $ 76,880 $ 75,525 $ 29,474 +(Decrease) increase in asset retirement obligations related to mineral properties $ ( 208 ) $ 2,912 $ 2,614 +Increase in asset retirement obligations related to midstream properties $ 690 $ 1,204 $ 686 +Decrease in liabilities for drilling, completion and equipping capital expenditures $ ( 26,126 ) $ ( 13,310 ) $ ( 21,032 ) +(Decrease) increase in liabilities for acquisition of oil and natural gas properties $ ( 2,346 ) $ ( 2,567 ) $ 4,230 +(Decrease) increase in liabilities for midstream capital expenditures $ ( 33,609 ) $ 30,374 $ 2,499 +Stock-based compensation expense (benefit) recognized as liability $ 3,702 $ 3,170 $ ( 1,069 ) +Increase in liabilities for accrued cost to issue senior notes $ — $ — $ 232 +Transfer of inventory from oil and natural gas properties $ 608 $ 1,515 $ 409 +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 15 — SUPPLEMENTAL DISCLOSURES — Continued +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2020 2019 2018 +Cash $ 57,916 $ 40,024 $ 64,545 +Restricted cash 33,467 25,104 19,439 +Total cash and restricted cash $ 91,383 $ 65,128 $ 83,984 +NOTE 16 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin are conducted through San Mateo (see Note 6). +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2020 +Oil and natural gas revenues $ 741,092 $ 3,369 $ — $ — $ 744,461 +Midstream services revenues — 166,194 — ( 101,262 ) 64,932 +Sales of purchased natural gas 20,736 21,006 — — 41,742 +Lease bonus - mineral acreage 4,062 — — — 4,062 +Realized gain on derivatives 38,937 — — — 38,937 +Unrealized loss on derivatives ( 32,008 ) — — — ( 32,008 ) +Expenses (1) +1,334,378 97,599 52,910 ( 101,262 ) 1,383,625 +Operating (loss) income (2) +$ ( 561,559 ) $ 92,970 $ ( 52,910 ) $ — $ ( 521,499 ) +Total assets (3) +$ 2,782,819 $ 836,509 $ 67,952 $ — $ 3,687,280 +Capital expenditures (4) +$ 518,198 $ 201,440 $ 2,200 $ — $ 721,838 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 335.8 million and $ 23.3 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $ 684.7 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $ 2.7 million. +(2) Includes $ 39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2019 +Oil and natural gas revenues $ 886,127 $ 6,198 $ — $ — $ 892,325 +Midstream services revenues — 135,953 — ( 76,843 ) 59,110 +Sales of purchased natural gas 4,802 69,967 — — 74,769 +Lease bonus - mineral acreage 1,711 — — — 1,711 +Realized gain on derivatives 9,482 — — — 9,482 +Unrealized loss on derivatives ( 53,727 ) — — — ( 53,727 ) +Expenses (1) +621,687 130,612 72,734 ( 76,843 ) 748,190 +Operating income (loss) (2) +$ 226,708 $ 81,506 $ ( 72,734 ) $ — $ 235,480 +Total assets (3) +$ 3,360,725 $ 647,937 $ 61,014 $ — $ 4,069,676 +Capital expenditures (4) +$ 718,712 $ 223,612 $ 3,701 $ — $ 946,025 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 331.7 million and $ 16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.7 million. +(2) Includes $ 35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2018 +Oil and natural gas revenues $ 794,261 $ 6,439 $ — $ — $ 800,700 +Midstream services revenues — 86,737 — ( 64,817 ) 21,920 +Sales of purchased natural gas 902 6,169 — — 7,071 +Lease bonus - mineral acreage 2,489 — — — 2,489 +Realized gain on derivatives 2,334 — — — 2,334 +Unrealized gain on derivatives 65,085 — — — 65,085 +Expenses (1) +487,539 44,098 69,508 ( 64,817 ) 536,328 +Operating income (loss) (2) +$ 377,532 $ 55,247 $ ( 69,508 ) $ — $ 363,271 +Total assets (3) +$ 2,910,326 $ 439,953 $ 105,239 $ — $ 3,455,518 +Capital expenditures (4) +$ 1,335,690 $ 166,407 $ 2,562 $ — $ 1,504,659 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 252.3 million and $ 10.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.4 million. +(2) Includes $ 25.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 656.9 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 80.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2020, 2019 and 2018 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2020, 2019 and 2018 (in thousands). +Year Ended December 31, +2020 2019 2018 +Property acquisition costs +Proved $ 8,003 $ 3,767 $ 4,788 +Unproved and unevaluated 61,984 39,595 633,502 +Exploration costs 29,370 109,439 229,974 +Development costs 418,841 570,290 467,426 +Total costs incurred (1) +$ 518,198 $ 723,091 $ 1,335,690 +__________________ +(1) Excludes midstream-related development and corporate costs of approximately $203.6 million, $227.3 million and $169.0 million for the years ended December 31, 2020, 2019 and 2018, respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2020, 2019 and 2018, most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the years ended December 31, 2020, 2019 and 2018, the Company capitalized zero, $2.9 million and $17.7 million, respectively, of geological and geophysical costs, which are included as exploration costs in the table above. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were a reduction of $0.2 million and increases of $4.3 million and $4.0 million for the years ended December 31, 2020, 2019 and 2018, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $30.0 million, $31.1 million and $28.3 million of these internal costs for the years ended December 31, 2020, 2019 and 2018, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $5.0 million, $7.6 million and $8.8 million of its interest expense for the years ended December 31, 2020, 2019 and 2018, respectively, excluding midstream-related capitalized interest expense. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2020, 2019 and 2018 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2020, 2019 and 2018 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. For the period from January through December 2018, these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2020, 2019 and 2018 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +Net Proved Reserves +Oil Natural Gas Oil +Equivalent +(MBbl) (MMcf) (MBOE) +Total at December 31, 2017 86,743 396,164 152,771 +Revisions of prior estimates 5,908 32,497 11,326 +Purchases of minerals in-place 446 900 596 +Extensions and discoveries 41,445 169,224 69,646 +Production (11,141) (47,311) (19,026) +Total at December 31, 2018 123,401 551,474 215,313 +Revisions of prior estimates (605) 34,062 5,073 +Net divestitures of minerals-in-place (298) (12,048) (2,307) +Extensions and discoveries 39,477 114,833 58,616 +Production (13,984) (61,083) (24,164) +Total at December 31, 2019 147,991 627,238 252,531 +Revisions of prior estimates 6,587 19,444 9,828 +Net acquisitions of minerals-in-place 11 1,078 190 +Extensions and discoveries 21,291 84,043 35,297 +Production (15,931) (69,501) (27,514) +Total at December 31, 2020 159,949 662,302 270,332 +Proved Developed Reserves +December 31, 2017 36,966 190,109 68,651 +December 31, 2018 53,223 246,229 94,261 +December 31, 2019 59,667 276,258 105,710 +December 31, 2020 69,647 323,160 123,507 +Proved Undeveloped Reserves +December 31, 2017 49,777 206,055 84,120 +December 31, 2018 70,178 305,245 121,052 +December 31, 2019 88,324 350,980 146,821 +December 31, 2020 90,301 339,142 146,825 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2020, 2019 and 2018. +The Company’s proved oil and natural gas reserves increased to 270,332 MBOE at December 31, 2020 from 252,531 MBOE at December 31, 2019. The Company’s proved oil and natural gas reserves increased by 45,315 MBOE and the Company produced 27,514 MBOE during the year ended December 31, 2020, resulting in a net increase of 17,801 MBOE. The Company’s proved oil and natural gas reserves increased by 35,297 MBOE during 2020 as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 9,828 MBOE during 2020 as a result of upward revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells, but these upward revisions were partially offset by downward revisions attributable to the lower weighted average oil and natural gas prices used to estimate proved reserves in 2020, as compared to 2019. The Company’s proved developed oil and natural gas reserves increased to 123,507 MBOE at December 31, 2020 from 105,710 +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2020, 2019 and 2018 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +MBOE at December 31, 2019, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2020, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 46% proved developed and approximately 54% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 252,531 MBOE at December 31, 2019 from 215,313 MBOE at December 31, 2018. The Company’s proved oil and natural gas reserves increased by 61,382 MBOE and the Company produced 24,164 MBOE during the year ended December 31, 2019, resulting in a net increase of 37,218 MBOE. The Company’s proved oil and natural gas reserves increased by 58,616 MBOE during 2019 as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 5,073 MBOE during 2019 as a result of upward revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells, but which were partially offset by downward revisions attributable to the lower weighted average oil and natural gas prices used to estimate proved reserves in 2019, as compared to 2018. The Company’s proved oil and natural gas reserves decreased 2,307 MBOE in 2019 as a result of net divestitures of minerals-in-place primarily in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. The Company’s proved developed oil and natural gas reserves increased to 105,710 MBOE at December 31, 2019 from 94,261 MBOE at December 31, 2018, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2019, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 42% proved developed and approximately 58% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 215,313 MBOE at December 31, 2018 from 152,771 MBOE at December 31, 2017. The Company’s proved oil and natural gas reserves increased by 81,568 MBOE and the Company produced 19,026 MBOE during the year ended December 31, 2018, resulting in a net increase of 62,542 MBOE. The Company’s proved oil and natural gas reserves increased by 69,646 MBOE as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 11,326 MBOE during 2018 as a result of upward revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted average oil and natural gas prices used to estimate proved reserves in 2018, as compared to 2017. The Company also added 596 MBOE in proved oil and natural gas reserves in 2018 as a result of purchases of minerals-in-place in the Delaware Basin. The Company’s proved developed oil and natural gas reserves increased to 94,261 MBOE at December 31, 2018 from 68,651 MBOE at December 31, 2017, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2018, the Company’s proved reserves were made up of approximately 57% oil and 43% natural gas and were approximately 44% proved developed and approximately 56% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2020, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, the comparable average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. For the period from January through December 2018, the comparable average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2020, 2019 and 2018 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2020, 2019 and 2018 (in thousands). +Year Ended December 31, +2020 2019 2018 +Future cash inflows $ 6,587,343 $ 8,771,595 $ 8,822,004 +Future production costs (2,606,956) (3,087,142) (2,713,043) +Future development costs (1,075,317) (1,638,744) (1,384,916) +Future income tax expense (228,848) (479,011) (710,222) +Future net cash flows 2,676,222 3,566,698 4,013,823 +10% annual discount for estimated timing of cash flows (1,091,823) (1,532,715) (1,763,210) +Standardized measure of discounted future net cash flows $ 1,584,399 $ 2,033,983 $ 2,250,613 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2020, 2019 and 2018 (in thousands). +Year Ended December 31, +2020 2019 2018 +Balance, beginning of period $ 2,033,983 $ 2,250,613 $ 1,258,646 +Net change in sales and transfer prices and in production (lifting) costs related to future production (1,126,777) (622,710) 574,381 +Changes in estimated future development costs 177,074 (284,748) (347,038) +Sales and transfers of oil and natural gas produced during the period (546,169) (682,747) (631,596) +Net purchases (divestitures) of reserves in place 1,803 (28,849) 9,227 +Net change due to extensions and discoveries 296,617 733,208 1,078,935 +Net change due to revisions in estimates of reserves quantities 93,066 63,436 175,440 +Previously estimated development costs incurred during the period 253,165 258,593 279,799 +Accretion of discount 240,728 237,548 103,085 +Other 16 (4,861) 3,600 +Net change in income taxes 160,893 114,500 (253,866) +Standardized measure of discounted future net cash flows $ 1,584,399 $ 2,033,983 $ 2,250,613 +F-42 \ No newline at end of file diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/filing_metadata.csv b/raw/filings/0001520006/2020/0001520006-21-000056/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..70035f393a80cd0a9692a3bd60eb6fb87ac81bf8 --- /dev/null +++ b/raw/filings/0001520006/2020/0001520006-21-000056/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2021-02-26,2020-12-31,2021-02-27T03:18:23.000Z,0001520006-21-000056,mtdr-20201231.htm,10-K,15239848,1,1,https://www.sec.gov/Archives/edgar/data/1520006/000152000621000056/mtdr-20201231.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000621000056/,2020,2020,1 diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/item1.txt b/raw/filings/0001520006/2020/0001520006-21-000056/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c20b41995032f00d5dd35e097d7f674cdbb121ba --- /dev/null +++ b/raw/filings/0001520006/2020/0001520006-21-000056/item1.txt @@ -0,0 +1,579 @@ +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo I”) together with San Mateo Midstream II, LLC (collectively with its subsidiaries, “San Mateo II”). Effective October 1, 2020, San Mateo II merged with and into San Mateo I. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +2 +Table of Contents +• maintain our financial discipline; and +• pursue opportunistic acquisitions, divestitures and joint ventures. +Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, the successful execution of our business strategies led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2020. We achieved these results despite reducing our operated drilling rig count from six at the beginning of the year to three by the end of the second quarter. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”). In addition, we concluded several important financing transactions in 2020, including an increase in the elected commitment under our Credit Agreement (as defined below), the affirmation of the borrowing base and the restructuring of our oil hedging portfolio. San Mateo also achieved several important milestones in 2020, including the expansion of its cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and associated pipelines and the merger of San Mateo II with and into San Mateo I. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2020 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2020, we achieved record oil, natural gas and average daily oil equivalent production. In 2020, we produced 15.9 million Bbl of oil, an increase of 14%, as compared to 14.0 million Bbl of oil produced in 2019. We also produced 69.5 Bcf of natural gas, an increase of 14% from 61.1 Bcf of natural gas produced in 2019. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, an increase of 14%, as compared to 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, for the year ended December 31, 2019. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for both the years ended December 31, 2020 and December 31, 2019. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, an increase of 7% from 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, at December 31, 2019. The Standardized Measure of our total proved oil and natural gas reserves decreased 22% from $2.03 billion at December 31, 2019 to $1.58 billion at December 31, 2020. The PV-10 of our total proved oil and natural gas reserves decreased 26% from $2.25 billion at December 31, 2019 to $1.66 billion at December 31, 2020. The decreases in our Standardized Measure and PV-10 were primarily a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +Our proved oil reserves grew 8% to 159.9 million Bbl at December 31, 2020 from 148.0 million Bbl at December 31, 2019. Our proved natural gas reserves increased 6% to 662.3 Bcf at December 31, 2020 from 627.2 Bcf at December 31, 2019. This growth in oil and natural gas reserves was attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2020. +At December 31, 2020, proved developed reserves included 69.6 million Bbl of oil and 323.2 Bcf of natural gas, and proved undeveloped reserves included 90.3 million Bbl of oil and 339.1 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 46% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2020. Proved developed reserves and proved oil reserves comprised 42% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2019. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, +3 +Table of Contents +completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2021. +We completed and began producing oil and natural gas from 89 gross (47.8 net) wells in the Delaware Basin in 2020, including 53 gross (45.6 net) operated and 36 gross (2.2 net) non-operated wells. At December 31, 2020, our total acreage position in the Delaware Basin was approximately 230,600 gross (124,700 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on the following asset areas: the Wolf and Jackson Trust asset areas in Loving County, Texas, the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 21% to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020, as compared to 55,599 BOE per day (84% of total oil equivalent production), including 35,184 Bbl of oil per day (92% of total oil production) and 122.5 MMcf of natural gas per day (73% of total natural gas production), in 2019. We expect our Delaware Basin production to increase in 2021 as we continue the delineation and development of these asset areas. +During 2020, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) were: +• we completed and turned to sales the first six Rodney Robinson wells, all of which were two-mile laterals, in the western portion of our Antelope Ridge asset area, in late March 2020; these six Rodney Robinson wells have produced in aggregate approximately 2.7 million BOE in approximately 10 months of production; +• we completed and turned to sales the first five Ray State wells, all of which were two-mile laterals, in the eastern portion of our Rustler Breaks asset area in late May and early June 2020; these five Ray State wells have produced in aggregate approximately 1.6 million BOE in just over seven months of production; +• we completed and turned to sales five Leatherneck wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in late July and early August 2020; these five Leatherneck wells have produced in aggregate approximately 1.0 million BOE in just over six months of production; +• we completed and turned to sales the first 13 Boros wells, all of which were two-mile laterals, in the eastern portion of the Stateline asset area in a staggered fashion during September 2020; these 13 Boros wells have produced in aggregate approximately 2.7 million BOE in just over four months of production, despite a number of these wells being produced on restricted chokes early in their production; and +• San Mateo completed the expansion of the Black River Processing Plant and associated pipelines and facilities in conjunction with the Boros and Leatherneck wells coming online. +In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2020 included: +• the ongoing transition to drilling longer laterals, whereby 83% of the operated horizontal wells we completed and turned to sales in 2020 had lateral lengths greater than one mile, as compared to 29% in 2019 and 9% in 2018; +• the continuing improvement in capital efficiency as demonstrated by (i) our average drilling and completion costs for all operated horizontal wells completed and turned to sales of approximately $850 per lateral foot in 2020, a decrease of 27% as compared to average drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 44% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018, and (ii) the sequential quarterly decrease in our drilling and completion costs per lateral foot on operated wells turned to sales throughout 2020, from $1,009 in the first quarter to $881 in the second quarter to $790 in the third quarter and, finally, to $625 in the fourth quarter; +• record-low unit operating costs for lease operating expenses of $3.81 per BOE and general and administrative expenses of $2.27 per BOE; +• in our Wolf asset area, the results from our first Third Bone Spring Carbonate test in the Delaware Basin, demonstrating the prospectivity of this formation throughout the basin; and +• in our Rustler Breaks asset area, the results from our first Third Bone Spring Sand test, demonstrating the prospectivity of this formation in that asset area. +4 +Table of Contents +Financing Highlights +We concluded several important financing transactions in 2020 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the amendment of our third amended and restated credit agreement (the “Credit Agreement”) in February 2020 to reaffirm the borrowing base at $900.0 million, increase our elected borrowing commitment from $500.0 million to $700.0 million and add two new banks to our lending group; +• the reaffirmation of the borrowing base under the Credit Agreement in October 2020; and +• the restructuring of a portion of our then-existing 2020 NYMEX West Texas Intermediate (“WTI”) oil derivative financial instruments in April 2020 to provide additional revenue assurance had oil prices declined further and help us remain in compliance with our Credit Agreement leverage covenant in 2020. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Effective October 1, 2020, together with our joint venture partner, a subsidiary of Five Point Energy LLC (“Five Point”), we completed the successful merger of San Mateo II with and into San Mateo I. San Mateo is owned 51% by us and 49% by Five Point. +San Mateo achieved strong operating results in 2020, highlighted by (i) increased midstream services revenues, (ii) increased produced water handling volumes and (iii) increased oil gathering and transportation volumes, all as compared to 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but, on a quarterly sequential basis, San Mateo’s natural gas gathering and processing volumes, water handling volumes and oil gathering and transportation volumes all increased significantly in the fourth quarter of 2020, as compared to the third quarter, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant, which added an incremental designed inlet capacity of 200 MMcf of natural gas per day to the previously designed inlet capacity of 260 MMcf per day for a total designed inlet capacity of 460 MMcf per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2020, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo also completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). In addition, San Mateo completed and placed in service approximately 19 miles of various diameter crude oil pipelines from certain points of origin in the Greater Stebbins Area to the existing San Mateo interconnect with a subsidiary of Plains All American Pipeline, L.P. (“Plains”) in Eddy County, New Mexico. At December 31, 2020, San Mateo was gathering or transporting our oil and natural gas production via pipeline in both the Stateline asset area and the Greater Stebbins Area, as well as in the Wolf and Rustler Breaks asset areas. San Mateo was handling our produced water via pipeline in each of these areas as well. +At December 31, 2020, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 140 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large-diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 13 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 335,000 Bbl per day and approximately 120 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +5 +Table of Contents +Environmental, Social and Governance (“ESG”) Initiatives +We maintain an active ESG program and continued working in 2020 to improve upon our various ESG efforts. For instance, we significantly increased the percentage of new production facilities operating on electrical grid power, lowering emissions by removing on-site generators. We also increased the percentage of recycled water used in our completions and increased the percentage of both produced water and oil we transported via pipeline. +Using batch drilling and longer laterals, we significantly increased our lateral footage drilled per new pad built, helping to reduce our surface footprint. Finally, we continued our commitment to a proactive safety culture, with approximately 2.1 million employee man-hours and no lost time accidents experienced from 2017 to 2020. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2020, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2020. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +230,600 124,700 831 398.5 4,359 1,502 261,888 43.9 67,522 +South Texas: +Eagle Ford (5) +29,300 26,300 126 105.0 229 182 4,909 100.0 2,412 +Northwest Louisiana +Haynesville 16,700 9,100 237 18.8 163 16 3,486 100.0 5,015 +Cotton Valley (6) +16,100 14,900 64 39.7 154 35 49 100.0 226 +Area Total (7) +19,100 17,700 301 58.5 317 51 3,535 100.0 5,241 +Total 279,000 168,700 1,258 562.0 4,905 1,735 270,332 45.7 75,175 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2020. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2020, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of two miles or greater, and approximately 80% are expected to have lateral lengths of 1.5 miles or greater. At December 31, 2020, these engineered drilling locations included only 358 gross (145 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, in the Delaware Basin. At December 31, 2020, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale or the Haynesville shale, primarily as a result of the significantly lower oil and natural gas prices used to estimate proved reserves at December 31, 2020, which were $36.04 per Bbl and $1.99 per MMBtu, respectively, as compared to prior periods. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2020. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +6 +Table of Contents +We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2020, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2020, we also were the operator for approximately 93% of our Eagle Ford acreage and approximately 52% of our Haynesville acreage, including approximately 8% of our acreage in what we believe is the core area of the Haynesville play. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2020, our total acreage position in Southeast New Mexico and West Texas was approximately 230,600 gross (124,700 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 34,600 gross (18,400 net) acres in our Ranger asset area in Lea County, 66,000 gross (26,800 net) acres in our Arrowhead asset area in Eddy County, 47,900 gross (26,200 net) acres in our Rustler Breaks asset area in Eddy County, 23,200 gross (16,000 net) acres in our Antelope Ridge asset area in Lea County, 15,100 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our Stateline asset area in Eddy County and 40,500 gross (23,200 net) acres in our Twin Lakes asset area in Lea County at December 31, 2020. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2020, our acreage position in the Delaware Basin was approximately 67% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 79% held by existing production at December 31, 2020. +During the year ended December 31, 2020, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 89 gross (47.8 net) wells in the Delaware Basin, including 53 gross (45.6 net) operated horizontal wells and 36 gross (2.2 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2020, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, the Avalon, the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +7 +Table of Contents +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2020. Our average daily oil equivalent production from the Delaware Basin increased approximately 21% to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020, as compared to 55,599 BOE per day (84% of total oil equivalent production), including 35,184 Bbl of oil per day (92% of total oil production) and 122.5 MMcf of natural gas per day (73% of total natural gas production), in 2019. Our average daily oil equivalent production from the Delaware Basin also grew approximately 26% from 61,493 BOE per day in the fourth quarter of 2019 to 77,367 BOE per day in the fourth quarter of 2020. +At December 31, 2020, approximately 97% of our estimated total proved oil and natural gas reserves, or 261.9 million BOE, was attributable to the Delaware Basin, including approximately 156.3 million Bbl of oil and 633.5 Bcf of natural gas, a 12% increase, as compared to 232.8 million BOE for the year ended December 31, 2019. Our Delaware Basin proved reserves at December 31, 2020 comprised approximately 98% of our proved oil reserves and 96% of our proved natural gas reserves, as compared to approximately 94% of our proved oil reserves and 89% of our proved natural gas reserves at December 31, 2019. +At December 31, 2020, we had identified 4,359 gross (1,502 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,091 gross (1,298 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2020, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of two miles or greater and approximately 80% are expected to have horizontal lateral lengths greater than 1.5 miles. At and prior to December 31, 2019, all of our identified horizontal drilling locations were based on the assumptions of a one-mile lateral being drilled at each location. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations at December 31, 2020 do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2020, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2020, these potential future drilling locations included 358 gross (145 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves. +At December 31, 2020, we were operating three drilling rigs in the Delaware Basin, and we expect to operate three rigs in the Delaware Basin during most of the first quarter of 2021. We expect to add a fourth rig in March 2021 and to operate four rigs in the Delaware Basin throughout the remainder of 2021. Two of these operated rigs are expected to operate full-time in the Stateline asset area. The other two rigs are expected to operate in certain of our other asset areas, including the Greater Stebbins Area, the Wolf asset area, the Ranger asset area and the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area. We have built significant optionality into our drilling program, which allowed us to decrease the number of rigs in 2020 from six to three within a few months and should generally allow us to increase or decrease the number of rigs we operate as necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2021. +Antelope Ridge Asset Area - Lea County, New Mexico +At the end of the first quarter of 2020, we achieved the first of the five operational milestones we set for Matador in 2020 when we completed and turned to sales our first six gross (6.0 net) wells on the Rodney Robinson leasehold. These wells also were the first wells drilled on acreage acquired in the BLM Acquisition. Including the Rodney Robinson wells, we completed and turned to sales 12 gross (11.4 net) operated and 15 gross (0.3 net) non-operated wells in the Antelope Ridge asset area during 2020. +The 1,200 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired as part of the of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. The six Rodney Robinson wells, which included two Wolfcamp A-XY completions, two Second Bone Spring completions, one Upper Avalon completion and one Lower Avalon completion, were turned to sales late in the first quarter of 2020 and were all two-mile laterals. The 24-hour initial potential (“IP”) test results from all six Rodney Robinson wells totaled 19,236 BOE per day (79% oil). Notably, these IP test results included, at the time, the best IP test results we had achieved for wells completed and turned to sales in the Avalon, Second Bone Spring and Wolfcamp A-XY formations throughout the Delaware Basin. These +8 +Table of Contents +six Rodney Robinson wells have produced in aggregate approximately 2.7 million BOE in approximately 10 months of production. We drilled four additional Rodney Robinson wells in the fall of 2020, and these four wells are expected to be completed and turned to sales late in the first quarter of 2021. +Rustler Breaks Asset Area - Eddy County, New Mexico +In the Rustler Breaks asset area, we completed and turned to sales 13 gross (7.8 net) operated wells and 21 gross (1.9 net) non-operated wells during 2020. +During the second quarter of 2020, we achieved the second of the five operational milestones we set for Matador in 2020 when we completed and turned to sales five wells on our Ray State leasehold in the eastern portion of the Rustler Breaks asset area in late May and early June. These five wells, which were all-two mile laterals, included two Wolfcamp A-XY completions, one Wolfcamp A-Lower completion and two Wolfcamp B-Blair completions. The 24-hour IP aggregate test results for the five Ray State wells were 12,507 BOE per day (61% oil). These five Ray State wells have produced in aggregate approximately 1.6 million BOE in just over seven months of production. +During the fourth quarter of 2020, we completed and turned to sales three wells on our Ace Stern Vegas leasehold in northeast Rustler Breaks, including two Wolfcamp A-XY completions and one Third Bone Spring completion. The 24-hour IP aggregate test results for these three wells, which were all two-mile laterals, were 7,415 BOE per day (74% oil). We believe these three wells demonstrate the prospectivity of the northeastern portion of our Rustler Breaks acreage. +Arrowhead, Ranger and Twin Lakes Asset Areas - Eddy and Lea Counties, New Mexico +During the third quarter of 2020, we achieved the third of the five operational milestones we set for Matador in 2020 when we completed and turned to sales five gross (4.3 net) operated wells, all of which were two-mile laterals, on the Leatherneck tract in the Greater Stebbins Area. These five Leatherneck wells have produced in aggregate approximately 1.0 million BOE in just over six months of production. We did not complete or turn to sales any other operated or non-operated wells in other portions of the Arrowhead asset area or in the Ranger or Twin Lakes asset areas during 2020. +We were pleased with the performance from the five Leatherneck wells, which included two Third Bone Spring completions, two Wolfcamp A-XY completions and one Wolfcamp B completion. The Wolfcamp B completion was particularly noteworthy, being our first test of the Wolfcamp B formation this far north in the Delaware Basin. This Wolfcamp B completion tested 2,101 BOE per day (71% oil) during its 24-hour IP test. We believe these results provide evidence of Wolfcamp B prospectivity moving north in the Delaware Basin. +Stateline Asset Area - Eddy County, New Mexico +We operated two drilling rigs in our Stateline asset area for the majority of 2020 and expect to do so again in 2021. In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net leasehold acres prospective for multiple geologic targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We plan to develop this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.5-mile laterals on the western side of the leasehold. We began drilling operations in the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we achieved the last two of the five operational milestones we set for Matador in 2020 when we completed and turned to sales our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area and connected these wells to the expanded Black River Processing Plant and associated pipeline and facilities discussed below. +The 13 Boros wells, all of which were two-mile laterals, tested six different intervals and included one Avalon completion, two Second Bone Spring completions, four Wolfcamp A-XY completions, four Wolfcamp A-Lower completions, one Wolfcamp B-Upper completion and one Wolfcamp B-Lower completion. In aggregate, these 13 Boros wells tested 45,225 BOE per day (56% oil), and the IP test results from the two Second Bone Spring completions were the top two IP test results that we had reported to date for wells completed and turned to sales in that formation throughout the Delaware Basin. Similarly, the IP test results for three of the Wolfcamp A-Lower completions were three of the top four IP test results that we had achieved to date for wells completed and turned to sales in the Wolfcamp A-Lower formation. In addition, most of these 24-hour IP test results were recorded at high flowing casing pressures of between 3,000 and 4,200 pounds per square inch (“psi”) in the Wolfcamp A-XY, Wolfcamp A-Lower and Wolfcamp B formations, further indicating the potential of these wells. These 13 Boros wells have produced in aggregate approximately 2.7 million BOE in just over four months of production, despite a number of these wells being produced on restricted chokes early in their production. +In addition, during 2020, we drilled 13 wells on the Voni tract on the western portion of the Stateline leasehold. These 13 Voni wells are expected to have completed lateral lengths of approximately 12,000 feet and should be completed in the first quarter of 2021 and turned to sales early in the second quarter of 2021. +9 +Table of Contents +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we completed and turned to sales 10 gross (9.1 net) operated wells during 2020. The Larson 04-TTT-B02 WF #136H (Larson #136H) well in the Wolf asset area was particularly significant, being our first test of the Third Bone Spring Carbonate formation in the Delaware Basin. The Larson #136H well tested 1,668 BOE per day (68% oil) from a completed lateral length of 7,443 feet. We believe this test result indicates the prospectivity of the Third Bone Spring Carbonate, not only in the Wolf asset area, but also in our other asset areas throughout the Delaware Basin. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2020, our properties included approximately 29,300 gross (26,300 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 87% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. Approximately 99% of our Eagle Ford acreage was held by production at December 31, 2020. +We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2020. In fact, as of December 31, 2020, we had not completed any wells in the Eagle Ford shale in over 18 months. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 40% to 2,412 BOE per day, including 1,840 Bbl of oil per day and 3.4 MMcf of natural gas per day, during 2020, as compared to 4,009 BOE per day, including 3,113 Bbl of oil per day and 5.4 MMcf of natural gas per day, during 2019. For the year ended December 31, 2020, 3% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 6% for the year ended December 31, 2019. +At December 31, 2020, approximately 2% of our estimated total proved oil and natural gas reserves, or 4.9 million BOE, was attributable to the Eagle Ford shale, including approximately 3.6 million Bbl of oil and 7.8 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2020, as compared to approximately 6% of our proved oil reserves and 3% of our proved natural gas reserves at December 31, 2019. +At December 31, 2020, we had identified 229 gross (182 net) engineered locations for potential future drilling on our Eagle Ford acreage. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to almost two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2020, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the prospectivity of these intervals. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +10 +Table of Contents +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2020, although we did participate in the drilling and completion of four gross (less than 0.1 net) non-operated Haynesville shale wells that were turned to sales in 2020. In the first quarter of 2020, we leased 2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained royalty interests ranging from 18% to 20%. This lessee drilled four wells in the second half of 2020. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2021. +At December 31, 2020, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including 16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,800 net) acres that we consider to be in the core area of the Haynesville shale play. +For the year ended December 31, 2020, approximately 7% of our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2019, approximately 10% of our average daily oil equivalent production, or 6,595 BOE per day, including 15 Bbl of oil per day and 39.5 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2020, approximately 17% of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2019, approximately 24% of our daily natural gas production, or 39.5 MMcf of natural gas per day, was attributable to these properties. At December 31, 2020, just over 1% of our estimated total proved reserves, or 3.5 million BOE, was attributable to our properties in Northwest Louisiana. +At December 31, 2020, we had identified 163 gross (16 net) engineered locations for potential future drilling in the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to two miles, with most being two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other factors. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo I, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo I included (i) the Black River Processing Plant (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo I and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 23, 2021, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through February 23, 2021, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019 and 2020, and we expect Five Point to pay us an additional $14.7 million in performance incentives in the first quarter of 2021. We may earn up to the remaining $14.7 million in San Mateo I performance incentives over the next two years. In connection with the formation of San Mateo I, we dedicated to San Mateo I current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo I pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each +11 +Table of Contents +company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in deferred performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of 2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives from Five Point. At February 23, 2021, we had received $0.7 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo I. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2020, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2020, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area. +In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline. +At December 31, 2020, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2020, San Mateo gathered approximately 73.9 Bcf of natural gas, a decrease of 4%, as compared to 77.2 Bcf of natural gas gathered during the year ended December 31, 2019. In addition, during the year ended December 31, 2020, San Mateo processed approximately 60.8 Bcf of natural gas at the Black River Processing Plant, a decrease of 6%, as compared to 64.7 Bcf of natural gas processed during the year ended December 31, 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but San Mateo’s sequential natural gas gathering and processing volumes increased significantly in the fourth quarter of 2020, as compared to the third quarter of 2020, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer +12 +Table of Contents +producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +In 2020, San Mateo completed and placed into service (i) a crude oil gathering and transportation system in the Greater Stebbins Area, which was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2020, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. +At December 31, 2020, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains and two trucking facilities. During the year ended December 31, 2020, the San Mateo Oil Pipeline Systems had throughput of approximately 11.6 million Bbl of oil, an increase of 32%, as compared to throughput of approximately 8.9 million Bbl of oil during the year ended December 31, 2019. +Produced Water Gathering and Disposal Assets +During 2020, San Mateo placed into service one commercial salt water disposal well in the Rustler Breaks asset area, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to eight. In addition to its eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, at February 23, 2021, San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, two commercial salt water disposal wells and associated facilities in the Greater Stebbins Area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 23, 2021, San Mateo had designed disposal capacity of approximately 335,000 Bbl of produced water per day. +During the year ended December 31, 2020, San Mateo handled approximately 84.8 million Bbl of produced water, an increase of 15%, as compared to approximately 73.9 million Bbl of produced water handled during the year ended December 31, 2019. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases and from third parties. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2020, 2019 and 2018. +Year Ended December 31, +2020 2019 2018 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 15,931 13,984 11,141 +Natural gas (Bcf) 69.5 61.1 47.3 +Total oil equivalent (MBOE) (1) +27,514 24,164 19,026 +Average daily production (BOE/d) (1) +75,175 66,203 52,128 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 37.38 $ 54.34 $ 57.04 +Oil, with realized derivatives (per Bbl) $ 39.83 $ 54.98 $ 57.38 +Natural gas, without realized derivatives (per Mcf) $ 2.14 $ 2.17 $ 3.49 +Natural gas, with realized derivatives (per Mcf) $ 2.14 $ 2.18 $ 3.46 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 3.39 $ 3.82 $ 4.00 +Lease operating $ 3.81 $ 4.85 $ 4.89 +Plant and other midstream services operating $ 1.51 $ 1.52 $ 1.29 +Depletion, depreciation and amortization $ 13.15 $ 14.51 $ 13.94 +General and administrative $ 2.27 $ 3.31 $ 3.64 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 15,254 674 — 3 15,931 +Natural gas (Bcf) 56.8 1.2 11.0 0.5 69.5 +Total oil equivalent (MBOE) (3) +24,713 883 1,835 83 27,514 +Percentage of total annual net production 89.8 % 3.2 % 6.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 41,678 1,840 — 8 43,526 +Natural gas (MMcf/d) 155.1 3.4 30.1 1.3 189.9 +Total oil equivalent (BOE/d) 67,522 2,412 5,015 226 75,175 +Average Sales Prices (4) +Oil (per Bbl) $ 37.38 $ 37.42 $ 28.77 $ 38.31 $ 37.38 +Natural gas (per Mcf) $ 2.23 $ 2.82 $ 1.66 $ 1.69 $ 2.14 +Total oil equivalent (per BOE) $ 28.19 $ 32.56 $ 9.94 $ 11.09 $ 27.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.52 $ 20.52 $ 4.71 $ 19.39 $ 5.09 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 12,843 1,136 — 5 13,984 +Natural gas (Bcf) 44.7 2.0 13.9 0.5 61.1 +Total oil equivalent (MBOE) (3) +20,294 1,463 2,316 91 24,164 +Percentage of total annual net production 84.0 % 6.0 % 9.6 % 0.4 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 35,184 3,113 — 15 38,312 +Natural gas (MMcf/d) 122.5 5.4 38.1 1.4 167.4 +Total oil equivalent (BOE/d) 55,599 4,009 6,345 250 66,203 +Average Sales Prices (4) +Oil (per Bbl) $ 53.95 $ 58.71 $ — $ 52.89 $ 54.34 +Natural gas (per Mcf) $ 2.11 $ 3.45 $ 2.16 $ 2.17 $ 2.17 +Total oil equivalent (per BOE) $ 38.80 $ 50.22 $ 12.99 $ 15.22 $ 36.93 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.22 $ 15.27 $ 4.36 $ 22.43 $ 5.81 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 10,230 907 — 4 11,141 +Natural gas (Bcf) 37.7 1.5 7.5 0.6 47.3 +Total oil equivalent (MBOE) (3) +16,512 1,152 1,247 115 19,026 +Percentage of total annual net production 86.8 % 6.0 % 6.6 % 0.6 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 28,026 2,485 — 13 30,524 +Natural gas (MMcf/d) 103.3 4.0 20.5 1.8 129.6 +Total oil equivalent (BOE/d) 45,237 3,158 3,417 316 52,128 +Average Sales Prices (4) +Oil (per Bbl) $ 56.12 $ 67.4 $ — $ 64.72 $ 57.04 +Natural gas (per Mcf) $ 3.55 $ 5.46 $ 2.85 $ 2.80 $ 3.49 +Total oil equivalent (per BOE) $ 42.88 $ 60.02 $ 17.09 $ 18.59 $ 42.08 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.79 $ 17.25 $ 5.41 $ 19.11 $ 5.68 +_________________ +(1) Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020 increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31, 2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for the year ended December 31, 2019. +Our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019 increased 27% from our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, as compared to 52,128 BOE per day for the year ended December 31, 2018. Our average daily oil production for the year ended December 31, 2019 was 38,312 Bbl of oil per day, an increase of 26% from 30,524 Bbl of oil per day for the year ended December 31, 2018. Our average daily natural gas production for the year ended December 31, 2019 was 167.4 MMcf of natural gas per day, an increase of 29% from 129.6 MMcf of natural gas per day for the year ended December 31, 2018. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2020. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 79% in all wells that we operated at December 31, 2020. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +673 322.1 158 76.4 831 398.5 +South Texas: +Eagle Ford (2) +122 101.0 4 4.0 126 105.0 +Northwest Louisiana: +Haynesville — — 237 18.8 237 18.8 +Cotton Valley (3) +1 1.0 63 38.7 64 39.7 +Area Total 1 1.0 300 57.5 301 58.5 +Total 796 424.1 462 137.9 1,258 562.0 +__________________ +(1) Includes 219 gross (62.6 net) vertical wells that were acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2020, 2019 and 2018. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +17 +Table of Contents +At December 31, (1) +2020 2019 2018 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 159,949 147,991 123,401 +Natural Gas (Bcf) 662.3 627.2 551.5 +Total (MBOE) (3) +270,332 252,531 215,313 +Estimated proved developed reserves: +Oil (MBbl) 69,647 59,667 53,223 +Natural Gas (Bcf) 323.2 276.3 246.2 +Total (MBOE) (3) +123,507 105,710 94,261 +Percent developed 45.7 % 41.9 % 43.8 % +Estimated proved undeveloped reserves: +Oil (MBbl) 90,301 88,324 70,178 +Natural gas (Bcf) 339.1 351.0 305.2 +Total (MBOE) (3) +146,825 146,821 121,052 +Standardized Measure (4) (in millions) +$ 1,584.4 $ 2,034.0 $ 2,250.6 +PV-10 (5) (in millions) +$ 1,658.0 $ 2,248.2 $ 2,579.3 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas, for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas and for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2020, 2019 and 2018 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2020, 2019 and 2018 were, in millions, $73.6, $214.2 and $328.7, respectively. +Our estimated total proved oil and natural gas reserves increased 7% from 252.5 million BOE at December 31, 2019 to 270.3 million BOE at December 31, 2020. This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2020. This increase in total proved reserves was achieved despite (i) the reduction in our operated rig count from six to three during 2020 and (ii) the 31% reduction in oil price and the 23% reduction in natural gas price used to estimate total proved reserves at December 31, 2020, as compared to December 31, 2019. We added 35.3 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2020, approximately 1.3 times our 2020 annual production of 27.5 million BOE. We also realized approximately 9.8 million BOE in net upward revisions to our proved reserves during 2020, primarily as a result of upward revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2019, which more than offset the downward revisions resulting from the significantly lower commodity prices used to estimate proved reserves at December 31, 2020. Our proved oil reserves grew 8% from approximately 148.0 million Bbl at December 31, 2019 to approximately 159.9 million Bbl at December 31, 2020. Our proved natural gas reserves increased 6% from 627.2 Bcf at December 31, 2019 to 662.3 Bcf at December 31, 2020. Our proved reserves to production ratio at December 31, 2020 was 9.8, a decrease of 7% from 10.5 at December 31, 2019. +Over the past two years, our estimated total proved oil and natural gas reserves increased 26% from 215.3 million BOE at December 31, 2018 to 270.3 million Bbl at December 31, 2020. Our proved oil reserves grew 30% from 123.4 million Bbl at December 31, 2018 to 159.9 million Bbl at December 31, 2020. Our proved developed oil reserves increased 31% from 53.2 million Bbl at December 31, 2018 to 69.6 million Bbl at December 31, 2020. +18 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves decreased 22% from $2.03 billion at December 31, 2019 to $1.58 billion at December 31, 2020. The PV-10 of our total proved oil and natural gas reserves decreased 26% from $2.25 billion at December 31, 2019 to $1.66 billion at December 31, 2020. The decreases in our Standardized Measure and PV-10 are primarily a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2020 were $36.04 per Bbl and $1.99 per MMBtu, a decrease of 31% and 23%, respectively, as compared to average oil and natural gas prices of $52.19 per Bbl and $2.58 per MMBtu used to estimate proved reserves at December 31, 2019. Our total proved reserves were made up of 59% oil and 41% natural gas at both December 31, 2020 and December 31, 2019. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +Our proved developed oil and natural gas reserves increased 17% from 105.7 million BOE at December 31, 2019 to 123.5 million BOE at December 31, 2020 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 17% from 59.7 million Bbl at December 31, 2019 to 69.6 million Bbl at December 31, 2020. Our proved developed natural gas reserves increased 17% from 276.3 Bcf at December 31, 2019 to 323.2 Bcf at December 31, 2020. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2020. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2019 105,710 +Extensions and discoveries 15,217 +Net acquisitions of minerals-in-place 190 +Revisions of prior estimates 960 +Production (27,514) +Conversion of proved undeveloped to proved developed 28,944 +As of December 31, 2020 123,507 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves were 146.8 million BOE at both December 31, 2019 and December 31, 2020, as the net additions to our proved undeveloped reserves of 28.9 million BOE offset the 28.9 million BOE we converted from proved undeveloped to proved developed reserves during 2020. Our proved undeveloped oil reserves increased 2% from 88.3 million Bbl at December 31, 2019 to 90.3 million Bbl at December 31, 2020. Our proved undeveloped natural gas reserves decreased 3% from 351.0 Bcf at December 31, 2019 to 339.1 Bcf at December 31, 2020. These changes in proved undeveloped oil and natural gas reserves were primarily the result of net increases in proved undeveloped reserves in the Delaware Basin resulting from our delineation and development operations there, which were offset by the conversion of proved undeveloped reserves to proved developed reserves and the removal of certain proved undeveloped reserves from total proved reserves at December 31, 2020, primarily as a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. +At December 31, 2020, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2020 within five years of booking these reserves. +19 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2020. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2019 146,821 +Extensions and discoveries 20,080 +Revisions of prior estimates 8,868 +Conversion of proved undeveloped to proved developed (28,944) +As of December 31, 2020 146,825 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth, since 2017, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2017 9,300 45.0 16,808 $ 211,860 +2018 16,009 61.7 26,283 356,830 +2019 13,832 58.8 23,629 318,609 +2020 16,256 76.1 28,944 257,590 +Total 55,397 241.6 95,664 $ 1,144,889 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2020. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 156,309 633.5 261,888 $ 1,538.2 $ 1,609.7 +South Texas: +Eagle Ford (5) +3,610 7.8 4,909 37.4 39.1 +Northwest Louisiana +Haynesville — 20.9 3,486 8.6 9.0 +Cotton Valley (6) +30 0.1 49 0.2 0.2 +Area Total 30 21.0 3,535 8.8 9.2 +Total 159,949 662.3 270,332 $ 1,584.4 $ 1,658.0 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2020 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2020 were approximately $73.6 million. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +20 +Table of Contents +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either volumetric and/or analogy methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. For 2020, our Executive Vice President of Reservoir Engineering and Chief Technology Officer was primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 43 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2020. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 165,800 83,300 64,800 41,400 230,600 124,700 +South Texas: +Eagle Ford 28,900 26,100 400 200 29,300 26,300 +Northwest Louisiana: +Haynesville 16,700 9,100 — — 16,700 9,100 +Cotton Valley 16,100 14,900 — — 16,100 14,900 +Area Total (1) +19,100 17,700 — — 19,100 17,700 +Total 213,800 127,100 65,200 41,600 279,000 168,700 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +21 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2020 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2026 and beyond totals 6,800 net acres, all of which is in the Delaware Basin. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2020. +Acres Acres Acres Acres Acres +Expiring 2021 Expiring 2022 Expiring 2023 Expiring 2024 Expiring 2025 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +29,300 15,800 19,600 10,200 5,600 5,200 1,300 1,100 2,300 2,300 +South Texas: +Eagle Ford 400 200 — — — — — — — — +Total 29,700 16,000 19,600 10,200 5,600 5,200 1,300 1,100 2,300 2,300 +__________________ +(1) Approximately 47% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our 2021 drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2020, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2020, 2019 and 2018 . +Year Ended December 31, +2020 2019 2018 +Gross Net Gross Net Gross Net +Development Wells +Productive 89 44.5 147 62.0 118 54.7 +Dry — — — — — — +Exploration Wells +Productive 4 3.3 25 13.3 35 20.8 +Dry — — — — — — +Total Wells +Productive 93 47.8 172 75.3 153 75.5 +Dry — — — — — — +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +22 +Table of Contents +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, domestic or global health concerns such as COVID-19, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2020, 2019 and 2018, we had two, two and four significant purchasers that accounted for approximately 65%, 67% and 60%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” in January 2021, the Biden administration issued certain orders limiting the issuance of federal drilling permits and other necessary federal approvals. The +23 +Table of Contents +impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems in production and markets relating to a particular area could have a material impact on our business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, +24 +Table of Contents +the prohibition, restriction or limitation of venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior dated January 20, 2021 providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The impact of the federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 66 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not +25 +Table of Contents +unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would have started at $0.60 per MMBtu in 2020 and escalated to $3.00 per MMBtu by 2024. Although the bill did not pass, any such surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would adversely affect the prices we receive for our natural gas processed in New Mexico. In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows” and “Risk Factors—Risks Related to Laws and Regulations—The Tax Cuts and Jobs Act may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers to fully offset our taxable income in future periods.” +26 +Table of Contents +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs +27 +Table of Contents +and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015 rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and the promulgation of the NWPR. +Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the U.S. Fish and Wildlife Service (the “USFWS”) under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order is currently on appeal in the Ninth Circuit Court of Appeals. However, the Montana district court’s decision spawned other NWP 12-based challenges and may indicate that the rest of the NWPs, some of which are relied upon for oil and natural gas projects, are vulnerable to similar challenge. The Corps has proposed a new set of NWPs, which would replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but has so far elected not to consult with the USFWS. If this status quo does not change, when the Corp re-issues the NWPs, the NWPs could be subject to the same legal challenges unless and until the ongoing litigation resolves the questions surrounding the need for a formal ESA consultation. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April +28 +Table of Contents +2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. Following that executive order, the New Mexico Oil Conservation Division (the “NMOCD”), New Mexico Environment Department (the “NMED”) and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions that would, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and +29 +Table of Contents +political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, they could have an adverse impact on our business, financial condition, results of operations and cash flows. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +As of December 31, 2020, approximately 28% of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain +30 +Table of Contents +relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. +Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2020, we had 288 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +31 +Table of Contents +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2020, for example, our employees completed approximately 15,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2020, we estimate our employees have worked approximately 2.1 million combined hours without experiencing a single lost time accident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group, which is devoted to proactively minimizing safety risks and addressing any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +32 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/item13.txt b/raw/filings/0001520006/2020/0001520006-21-000056/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2020/0001520006-21-000056/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/item9a.txt b/raw/filings/0001520006/2020/0001520006-21-000056/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..2731bf7915a2f93b8932a775055c55a463ddef08 --- /dev/null +++ b/raw/filings/0001520006/2020/0001520006-21-000056/item9a.txt @@ -0,0 +1,32 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls +90 +Table of Contents +and procedures were effective as of December 31, 2020 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2020, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2020 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 26, 2021 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 26, 2021 +92 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/rp_note.txt b/raw/filings/0001520006/2020/0001520006-21-000056/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2020/0001520006-21-000056/rpt_disclosure.txt b/raw/filings/0001520006/2020/0001520006-21-000056/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..990d6ab1f47ff2c0bd11cd391041b04e4b17e9a4 --- /dev/null +++ b/raw/filings/0001520006/2020/0001520006-21-000056/rpt_disclosure.txt @@ -0,0 +1,109 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed +below, during 2020 there was not, nor was there proposed as of December 31, 2020, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of +our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation +arrangements with directors and executive officers, which are described in “Executive Compensation—Compensation Discussion and Analysis” and “Director Compensation” above. +Working Interest and Overriding Royalty Interest Owners +Mr. Foran and certain of Mr. Foran’s affiliated +entities (collectively, the “Foran Entities”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest +owners, the Foran Entities are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Foran Entities are +entitled to receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2020, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners +or overriding royalty interest owners were approximately $1.9 million (the “Related Net Revenue Payments”). The Related Net Revenue Payments represent less than 1% of our total third-party net revenue payments during 2020. +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2020, our joint +interest billings to the Foran Entities attributable to their share of costs were approximately $1.8 million (the “Related Joint Interest Billings”). The Related Joint Interest Billings represent less than 1% of our total joint +interest billings during 2020. As a result of this ownership by the Foran Entities, from time to time, we will be in a net receivable or net payable position with certain of the Foran Entities. We do not consider any net receivables from the Foran +Entities to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Foran Entities for +potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s relationships and interests in such transactions and all other material facts related to the Related Net Revenue +Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments +and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Certain Employment Relationships +Billy E. Goodwin, Executive Vice President and Chief Operating +Officer—Drilling, Completions & Production, was appointed as an executive officer of the Company in connection with his February 2016 promotion to Senior Vice President—Operations. Two of Mr. Goodwin’s adult children +have been employees of the Company since 2014 and 2015, respectively, and each earned in 2020, and are expected to be compensated in 2021, between $120,000 and $500,000. One of Mr. Goodwin’s children has a Bachelor of Science degree in +Petroleum Engineering from the University of Tulsa and over 11 years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other child has a +Bachelor of Science in Business Administration degree in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He also has over 11 years of industry +experience, including as a drilling fluids engineer for a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangements for +potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangements and +2021 +Proxy Statement | Matador Resources Company 71 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +historical and anticipated compensation of Mr. Goodwin’s adult children, and all other material facts related to the relationship, determined that the employment arrangements were fair +to the Company and recommended +the employment arrangements to the full Board for approval and ratification. The Board subsequently approved and ratified such +employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s +sister-in-law has been an employee of the Company since 2016 and earned in 2020, and is expected to be compensated in 2021, between $120,000 and $200,000. +Mr. Baribault’s sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist +University Legal Assistants Program. She has over 39 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person +Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s +sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the +employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of +Mr. Foran has been an employee of the Company since 2015 and earned in 2020, and is expected to be compensated in 2021, between $120,000 and $200,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development +and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than 10 years of industry experience, including with another publicly traded exploration and production company. The Audit Committee +reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated +compensation of Mr. Foran’s adult child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval +and ratification. The Board subsequently approved and ratified such employment arrangement. +Procedures for Approval of Related Person +Transactions +Pursuant to the Related Person +Transaction Policy as in effect as of December 31, 2020, a “Related Person Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of +indebtedness)), or series of related transactions, or any material amendment to any such transaction, in which a Related Person (as defined below) has or will have a direct or indirect material interest and in which we are a participant, other than: +• +a transaction involving compensation of directors that is required to be reported in our proxy statement under Item 402 of +the SEC’s compensation disclosure requirements (“Item 402”); +• +any employment by us of an executive officer if: +o +the related compensation is required to be reported in our proxy statement under Item 402; or +o +the executive officer is not an “immediate family member” of another executive officer or director of the +Company, the related compensation would be reported in our proxy statement under Item 402 if the executive officer was a “named executive officer” and the Compensation Committee approved (or recommended that the Board approve) such +compensation; +• +a transaction with a Related Person involving less than $120,000; +• +a transaction in which the interest of the Related Person arises solely from the ownership of a class of our equity +securities and all holders of that class receive the same benefit on a pro rata basis; +• +a transaction in which a Related Person has an indirect interest solely as a result of being (a) a director or, +together with all other Related Persons, a less than 10% beneficial owner of an equity interest in another entity, or both, or (b) a limited partner in a partnership in which the Related Person, together with all other Related Persons, has an +interest of less than 10%; +72 Matador Resources Company | 2021 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that +involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority; +• +any transaction with another company at which a Related Person’s only relationship is as an employee (other than an +executive officer), if the aggregate amount involved does not exceed the greater of $1,000,000, or 2% of that company’s total annual revenues; +• +any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a +Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the lesser of $1,000,000, or 2% of the charitable organization’s total annual receipts; or +• +any transaction with another publicly traded company where the Related Person’s interest arises solely from beneficial +ownership of more than 5% of our Common Stock and ownership of a non-controlling interest in the other publicly traded company. +“Related Person” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors +or nominees for director; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, +sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law or person residing (other than a tenant or employee) in the home of a director, nominee for director, executive officer or a beneficial owner of more than 5% of +our Common Stock; and +• +any entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a +general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Person Transaction Policy, the Audit Committee must review all material facts of each Related Person Transaction and recommend either approval +or disapproval of the Related Person Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Person Transaction, the Audit Committee must, after reviewing all +material facts of the Related Person Transaction and the Related Person’s relationship and interest, determine whether the Related Person Transaction is fair to the Company. Further, the policy requires that all Related Person Transactions be +disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +2021 +Proxy Statement | Matador Resources Company 73 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/filing.txt b/raw/filings/0001520006/2021/0001520006-22-000065/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..b896ab93abdf3c40dcc8519fc178e816cc6f1c2b --- /dev/null +++ b/raw/filings/0001520006/2021/0001520006-22-000065/filing.txt @@ -0,0 +1,3212 @@ +mtdr-20211231 +0001520006 false 2021 FY P5Y P1M http://fasb.org/us-gaap/2021-01-31#OtherAssetsNoncurrent http://fasb.org/us-gaap/2021-01-31#OtherAssetsNoncurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2021-01-31#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2021-01-31#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2021-01-31#OtherLiabilitiesNoncurrent P3Y P5Y P6Y P3Y 0001520006 2021-01-01 2021-12-31 0001520006 2021-06-30 iso4217:USD 0001520006 2022-02-22 xbrli:shares 0001520006 2021-12-31 0001520006 2020-12-31 iso4217:USD xbrli:shares 0001520006 us-gaap:OilAndGasMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember 2019-01-01 2019-12-31 0001520006 2020-01-01 2020-12-31 0001520006 2019-01-01 2019-12-31 0001520006 us-gaap:CommonStockMember 2018-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2018-12-31 0001520006 us-gaap:RetainedEarningsMember 2018-12-31 0001520006 us-gaap:TreasuryStockMember 2018-12-31 0001520006 us-gaap:ParentMember 2018-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2018-12-31 0001520006 2018-12-31 0001520006 us-gaap:CommonStockMember 2019-01-01 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001520006 us-gaap:ParentMember 2019-01-01 2019-12-31 0001520006 us-gaap:TreasuryStockMember 2019-01-01 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember mtdr:SanMateoIMember 2019-01-01 2019-12-31 0001520006 us-gaap:ParentMember mtdr:SanMateoIMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIMember 2019-01-01 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember mtdr:SanMateoIIMember 2019-01-01 2019-12-31 0001520006 us-gaap:ParentMember mtdr:SanMateoIIMember 2019-01-01 2019-12-31 0001520006 us-gaap:NoncontrollingInterestMember mtdr:SanMateoIIMember 2019-01-01 2019-12-31 0001520006 mtdr:SanMateoIIMember 2019-01-01 2019-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2019-01-01 2019-12-31 0001520006 us-gaap:RetainedEarningsMember 2019-01-01 2019-12-31 0001520006 us-gaap:CommonStockMember 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2019-12-31 0001520006 us-gaap:RetainedEarningsMember 2019-12-31 0001520006 us-gaap:TreasuryStockMember 2019-12-31 0001520006 us-gaap:ParentMember 2019-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2019-12-31 0001520006 2019-12-31 0001520006 us-gaap:CommonStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-01-01 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-01-01 2020-12-31 0001520006 us-gaap:ParentMember 2020-01-01 2020-12-31 0001520006 us-gaap:TreasuryStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember mtdr:SanMateoIMember 2020-01-01 2020-12-31 0001520006 us-gaap:ParentMember mtdr:SanMateoIMember 2020-01-01 2020-12-31 0001520006 mtdr:SanMateoIMember 2020-01-01 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-01-01 2020-12-31 0001520006 us-gaap:CommonStockMember 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-12-31 0001520006 us-gaap:TreasuryStockMember 2020-12-31 0001520006 us-gaap:ParentMember 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-01-01 2021-12-31 0001520006 us-gaap:ParentMember 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-01-01 2021-12-31 0001520006 us-gaap:TreasuryStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember mtdr:SanMateoIMember 2021-01-01 2021-12-31 0001520006 us-gaap:ParentMember mtdr:SanMateoIMember 2021-01-01 2021-12-31 0001520006 mtdr:SanMateoIMember 2021-01-01 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-12-31 0001520006 us-gaap:TreasuryStockMember 2021-12-31 0001520006 us-gaap:ParentMember 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-12-31 0001520006 srt:MinimumMember 2021-01-01 2021-12-31 0001520006 srt:MaximumMember 2021-01-01 2021-12-31 mtdr:purchaser 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2021-01-01 2021-12-31 xbrli:pure 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2021-01-01 2021-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember mtdr:ExxonMobilCorporateMember us-gaap:RevenueFromContractWithCustomerMember 2021-01-01 2021-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember mtdr:BPAmericaProductionCompanyMember 2020-01-01 2020-12-31 0001520006 mtdr:TwoSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2020-01-01 2020-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2020-01-01 2020-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember mtdr:ExxonMobilCorporateMember us-gaap:RevenueFromContractWithCustomerMember 2020-01-01 2020-12-31 0001520006 mtdr:TwoSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2019-01-01 2019-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2019-01-01 2019-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember mtdr:BPAmericaProductionCompanyMember 2019-01-01 2019-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:AccountsReceivableMember us-gaap:CustomerConcentrationRiskMember 2021-01-01 2021-12-31 0001520006 us-gaap:AccountsReceivableMember us-gaap:CustomerConcentrationRiskMember mtdr:ExxonMobilCorporateMember 2020-01-01 2020-12-31 0001520006 us-gaap:AccountsReceivableMember us-gaap:CustomerConcentrationRiskMember mtdr:BPAmericaProductionCompanyMember 2019-01-01 2019-12-31 iso4217:USD utr:bbl iso4217:USD utr:MMBTU 0001520006 us-gaap:MachineryAndEquipmentMember 2021-01-01 2021-12-31 0001520006 srt:MinimumMember us-gaap:MachineryAndEquipmentMember 2021-01-01 2021-12-31 0001520006 srt:MaximumMember us-gaap:MachineryAndEquipmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2019-01-01 2019-12-31 0001520006 srt:OilReservesMember 2021-01-01 2021-12-31 0001520006 srt:OilReservesMember 2020-01-01 2020-12-31 0001520006 srt:OilReservesMember 2019-01-01 2019-12-31 0001520006 srt:NaturalGasReservesMember 2021-01-01 2021-12-31 0001520006 srt:NaturalGasReservesMember 2020-01-01 2020-12-31 0001520006 srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2020-01-01 2020-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2019-01-01 2019-12-31 0001520006 us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2021-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2020-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2021-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2020-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2021-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2020-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2021-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2020-12-31 0001520006 mtdr:CurrentYearMember 2021-12-31 0001520006 mtdr:PriorYearMember 2020-12-31 0001520006 mtdr:TwoYearsPriorMember 2019-12-31 0001520006 mtdr:ThreeYearsPriorMember 2019-12-31 0001520006 mtdr:ThreeYearsandPriorMember 2018-12-31 0001520006 mtdr:ProjectsInceptiontoDateMember 2021-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2021-01-01 2021-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasServiceMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasServiceMember 2020-01-01 2020-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2021-01-01 2021-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2020-01-01 2020-12-31 0001520006 mtdr:DrillingRigLeasesMember 2021-01-01 2021-12-31 0001520006 mtdr:DrillingRigLeasesMember 2020-01-01 2020-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2021-01-01 2021-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2020-01-01 2020-12-31 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2021-12-14 2021-12-14 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2021-12-14 0001520006 srt:MinimumMember mtdr:PropertiesInLeaAndEddyNMMember 2021-12-14 2021-12-14 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2021-12-31 utr:Boe 0001520006 srt:ProFormaMember mtdr:PropertiesInLeaAndEddyNMMember 2021-12-15 2021-12-15 0001520006 srt:ProFormaMember mtdr:PropertiesInLeaAndEddyNMMember 2021-12-16 2021-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2017-02-17 0001520006 mtdr:FivePointMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2021-12-31 mtdr:well 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2017-02-17 2017-02-17 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2021-02-23 2021-02-23 0001520006 mtdr:FivePointMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2017-02-17 2021-02-23 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2019-02-25 2019-02-25 0001520006 mtdr:FivePointMember 2021-01-01 2021-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:RustlerBreaksandWolfAssetAreaMember mtdr:SanMateoMidstreamMember 2017-02-17 2017-02-17 0001520006 us-gaap:CorporateJointVentureMember mtdr:RustlerBreaksAssetAreaMember mtdr:SanMateoMidstreamMember 2017-02-17 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember 2021-01-01 2021-12-31 0001520006 mtdr:SanMateoMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember mtdr:MatadorResourcesCompanyMember 2020-01-01 2020-12-31 0001520006 mtdr:FivePointMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2020-01-01 2020-12-31 0001520006 mtdr:FivePointMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2020-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember mtdr:MatadorResourcesCompanyMember 2019-01-01 2019-12-31 0001520006 mtdr:FivePointMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2019-01-01 2019-12-31 0001520006 mtdr:FivePointMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2019-12-31 0001520006 mtdr:PropertyContributionMember us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember mtdr:MatadorResourcesCompanyMember 2019-01-01 2019-03-31 0001520006 us-gaap:SeniorNotesMember us-gaap:UnsecuredDebtMember 2021-12-31 0001520006 mtdr:CreditAgreementMember us-gaap:LetterOfCreditMember 2021-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SBALoanCARESActMember 2021-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2021-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:FourthAmendedCreditAgreementMember 2021-11-18 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2021-11-01 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2021-11-30 0001520006 us-gaap:RevolvingCreditFacilityMember 2020-10-30 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2020-10-30 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2021-12-31 0001520006 2021-01-01 2021-02-23 0001520006 mtdr:FederalFundsEffectiveRateMember mtdr:ThirdAmendedCreditAgreementMember 2021-01-01 2021-12-31 0001520006 mtdr:LiborRateMember mtdr:ThirdAmendedCreditAgreementMember 2021-01-01 2021-12-31 0001520006 srt:MinimumMember mtdr:BaseRateLoanMember 2021-01-01 2021-12-31 0001520006 mtdr:BaseRateLoanMember mtdr:ThirdAmendedCreditAgreementMember srt:MaximumMember 2021-01-01 2021-12-31 0001520006 srt:MinimumMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:EurodollarMember 2021-01-01 2021-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MaximumMember us-gaap:EurodollarMember 2021-01-01 2021-12-31 0001520006 srt:MinimumMember mtdr:ThirdAmendedCreditAgreementMember 2021-01-01 2021-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MaximumMember 2021-01-01 2021-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2021-01-01 2021-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2018-12-19 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2019-10-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2021-06-30 0001520006 mtdr:SanMateoCreditFacilityMember 2021-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2021-01-01 2021-02-23 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember us-gaap:FederalFundsEffectiveSwapRateMember 2018-12-19 2018-12-19 0001520006 mtdr:SanMateoCreditFacilityMember mtdr:AdjustedLIBORateMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 srt:MinimumMember mtdr:SanMateoCreditFacilityMember mtdr:AdjustedLIBORateMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 srt:MaximumMember mtdr:SanMateoCreditFacilityMember mtdr:AdjustedLIBORateMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 srt:MinimumMember mtdr:SanMateoCreditFacilityMember mtdr:StatutoryReserveRateMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 srt:MaximumMember mtdr:SanMateoCreditFacilityMember mtdr:StatutoryReserveRateMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 srt:MinimumMember mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 srt:MaximumMember mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2018-12-19 2018-12-19 0001520006 mtdr:SanMateoCreditFacilityMember mtdr:TheBankOfNovaScotiaMember 2018-12-19 2018-12-19 0001520006 us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2026Member 2021-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:A2026NotesOfferingMember 2021-12-31 0001520006 us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember mtdr:SeniorNotesDue2026Member 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodThreeMember mtdr:SeniorNotesDue2026Member 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodFourMember mtdr:SeniorNotesDue2026Member 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodFiveMember mtdr:SeniorNotesDue2026Member 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember mtdr:Additional2026NotesMember 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember mtdr:Additional2026NotesMember 2018-10-04 0001520006 us-gaap:InternalRevenueServiceIRSMember 2021-12-31 0001520006 us-gaap:StateAndLocalJurisdictionMember 2021-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2021-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2021-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2021-01-01 2021-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2020-01-01 2020-12-31 0001520006 mtdr:RangeTwoMember 2021-01-01 2021-12-31 0001520006 mtdr:RangeTwoMember 2021-12-31 0001520006 mtdr:RangeFourMember 2021-01-01 2021-12-31 0001520006 mtdr:RangeFourMember 2021-12-31 0001520006 srt:MinimumMember mtdr:PerformanceBasedStockUnitsMember 2021-01-01 2021-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember srt:MaximumMember 2021-01-01 2021-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember 2021-01-01 2021-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2021-01-01 2021-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2021-01-01 2021-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2021-01-01 2021-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2021-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember mtdr:RestrictedStockUnitsPerformanceBasedMember 2021-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember srt:MaximumMember mtdr:RestrictedStockUnitsPerformanceBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2020-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2021-01-01 2021-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2020-01-01 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2021-12-31 0001520006 us-gaap:RestrictedStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2019-01-01 2019-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2021-01-01 2021-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2020-01-01 2020-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2019-01-01 2019-12-31 0001520006 2021-10-01 2021-12-31 0001520006 2021-10-01 2021-10-31 0001520006 srt:OilReservesMember mtdr:OpenCostlessCollarContractsMember 2021-12-31 utr:bbl 0001520006 srt:NaturalGasReservesMember mtdr:OpenCostlessCollarContractsMember mtdr:DerivativeContractCalculationPeriodOneMember 2021-12-31 0001520006 mtdr:OpenCostlessCollarContractsMember 2021-12-31 0001520006 mtdr:OpenBasisSwapContractsMember mtdr:OilBasisSwapsMember mtdr:DerivativeContractCalculationPeriodThreeMember 2021-12-31 0001520006 mtdr:OpenBasisSwapContractsMember 2021-12-31 0001520006 us-gaap:OtherCurrentAssetsMember 2021-12-31 0001520006 us-gaap:OtherCurrentLiabilitiesMember 2021-12-31 0001520006 us-gaap:OtherCurrentAssetsMember 2020-12-31 0001520006 us-gaap:OtherNoncurrentAssetsMember 2020-12-31 0001520006 us-gaap:OtherCurrentLiabilitiesMember 2020-12-31 0001520006 us-gaap:OtherNoncurrentLiabilitiesMember 2020-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2019-01-01 2019-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2019-01-01 2019-12-31 0001520006 mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 mtdr:RevenuesMember 2019-01-01 2019-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2021-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2021-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2021-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2021-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2020-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2020-12-31 0001520006 us-gaap:PipelinesMember 2021-01-01 2021-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2021-01-01 2021-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2020-01-01 2020-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2021-12-31 0001520006 mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember mtdr:SanMateoMidstreamMember 2021-01-01 2021-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2021-12-31 0001520006 mtdr:DrillingRigCommitmentsMember 2021-12-31 0001520006 srt:MinimumMember mtdr:DrillingRigCommitmentsMember 2021-01-01 2021-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2021-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2020-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2021-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2020-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2021-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2020-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2021-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2020-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2021-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2020-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2021-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2020-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2021-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2020-12-31 mtdr:segment 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2021-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2021-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2020-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2020-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:CorporateNonSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2019-01-01 2019-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2019-01-01 2019-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001520006 mtdr:ExplorationandProductionSegmentMember us-gaap:OperatingSegmentsMember 2019-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2019-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2019-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2019-12-31 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31 , 2021 +or +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-35410 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas 27-4662601 +(State or other jurisdiction of +incorporation or organization) (I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 75240 +Dallas, Texas +(Address of principal executive offices) (Zip Code) +( 972 ) 371-5200 +(Registrant’s telephone number, including area code) +_________________________________________________________ +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Trading symbol(s) Name of each exchange on which registered +Common Stock, par value $0.01 per share MTDR New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ☒ No ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ☐ No ☒ +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $ 3,979,787,498 . +As of February 22, 2022, there were 118,043,776 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Auditor Name: KPMG LLP +Auditor Location: Dallas, TX +Auditor Firm ID: 185 +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2021 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +34 +I TEM 1B. +Unresolved Staff Comments +64 +I TEM 2. +Properties +65 +I TEM 3. +Legal Proceedings +65 +I TEM 4. +Mine Safety Disclosures +65 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +66 +I TEM 6. +Selected Financial Data +69 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +69 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +88 +I TEM 8. +Financial Statements and Supplementary Data +90 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +90 +I TEM 9A. +Controls and Procedures +90 +I TEM 9B. +Other Information +93 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +93 +I TEM 11. +Executive Compensation +93 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +93 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +93 +I TEM 14. +Principal Accounting Fees and Services +93 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +94 +ITEM 16. +Form 10-K Summary +94 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus (“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of our midstream joint venture’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• our business strategy; +• our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized; +• our cash flows and liquidity; +• the amount, timing and payment of dividends, if any; +• our financial strategy, budget, projections and operating results; +• the supply and demand of oil, natural gas and natural gas liquids; +• oil, natural gas and natural gas liquids prices, including our realized prices thereof; +• the timing and amount of future production of oil and natural gas; +• the availability of drilling and production equipment; +• the availability of oil storage capacity; +• the availability of oil field labor; +• the amount, nature and timing of capital expenditures, including future exploration and development costs; +• the availability and terms of capital; +• our drilling of wells; +• our ability to negotiate and consummate acquisition and divestiture opportunities; +• the integration of acquisitions with our business; +• government regulation and taxation of the oil and natural gas industry; +• our marketing of oil and natural gas; +• our exploitation projects or property acquisitions; +• our ability and the ability of our midstream joint venture to construct, maintain and operate midstream pipelines and facilities, including the operation of its Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells; +• the ability of our midstream joint venture to attract third-party volumes; +• our costs of exploiting and developing our properties and conducting other operations; +• general economic conditions; +• competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• the effectiveness of our risk management and hedging activities; +• our technology; +• environmental liabilities; +• our initiatives and efforts relating to environmental, social and governance matters; +• counterparty credit risk; +1 +Table of Contents +• geopolitical instability and developments in oil-producing and natural gas-producing countries; +• the impact of COVID-19 on the oil and natural gas industry and our business; +• our future operating results; and +• our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, our midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• maintain our financial discipline; +2 +Table of Contents +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs and do so in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas prices improved significantly during 2021. These factors, along with the successful execution of our business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2021, as well as to increases in our oil and natural gas revenues and cash flows. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down borrowings, initiating and increasing a quarterly cash dividend and earning performance incentives from Five Point. Further, we concluded several important financing transactions in 2021, including extending the maturity of and significantly increasing the borrowing base under our Credit Agreement (as defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved several important milestones in 2021, including the addition of produced water disposal capacity and being awarded several new customer contracts. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2021 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2021, we achieved record oil, natural gas and average daily oil equivalent production. In 2021, we produced 17.8 million Bbl of oil, an increase of 12%, as compared to 15.9 million Bbl of oil produced in 2020. We also produced 81.7 Bcf of natural gas, an increase of 18% from 69.5 Bcf of natural gas produced in 2020. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended December 31, 2020. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2021 as compared to 58% in 2020. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, an increase of 20% from 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, at December 31, 2020. The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and PV-10 were primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2021, proved developed reserves included 102.2 million Bbl of oil and 546.2 Bcf of natural gas, and proved undeveloped reserves included 79.1 million Bbl of oil and 306.4 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 60% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2021. Proved developed reserves and proved oil reserves comprised 46% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2020. The improvement in proved developed reserves as a percentage of our total proved oil and natural gas reserves to 60% at December 31, 2021 from 46% at December 31, 2020 was primarily attributable to the development and conversion of approximately 40.1 million BOE of our proved undeveloped reserves to proved developed reserves in the Delaware Basin in 2021. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage +3 +Table of Contents +operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2022. +We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin in 2021, including 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells. At December 31, 2021, our total acreage position in the Delaware Basin was approximately 237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust asset areas in Loving County, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 19% to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020. We expect our Delaware Basin production to increase in 2022 as we continue the delineation and development of these asset areas. +During 2021, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +• the second group of Rodney Robinson wells in the western portion of our Antelope Ridge asset area, in March 2021; these four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in 11 months of production; +• the first 13 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a staggered fashion during April and May 2021; these 13 Voni wells have produced in aggregate approximately 5.2 million BOE in eight months of production; +• four wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in July 2021; these four wells have produced in aggregate approximately 0.7 million BOE in seven months of production; +• the second group of 13 Boros wells in the eastern portion of the Stateline asset area in a staggered fashion at various times primarily throughout September 2021; these 13 Boros wells have produced in aggregate approximately 2.2 million BOE in five months of production; and +• nine additional wells in the Greater Stebbins Area in December 2021. +In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2021 included: +• the fully realized transition to drilling longer laterals, whereby 98% of the operated horizontal wells we turned to sales in 2021 had lateral lengths of two miles or greater, as compared to 74% in 2020, 8% in 2019 and only one two-mile lateral in 2018; +• the continuing improvement in capital efficiency as demonstrated by our average drilling and completion costs for all operated horizontal wells turned to sales of approximately $670 per lateral foot in 2021, a decrease of 21% as compared to $850 per lateral foot in 2020, a decrease of 42% as compared to average drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 56% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018; +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2021 of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021, despite the acceleration of 11 Voni well completions forward into the fourth quarter of 2021 and the addition of a fifth operated drilling rig; +• record-low annual unit operating costs for lease operating expenses of $3.46 per BOE; +• general and administrative expenses of $3.06 per BOE, which were the second lowest general and administrative expenses we have achieved on an annual basis, as compared to a record low $2.27 per BOE in 2020. These 2021 general and administrative expenses were achieved despite the impact of increased cash-settled stock compensation costs and the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time. +4 +Table of Contents +Capital Resources and Financing Highlights +During 2021, we achieved several significant and important capital resources objectives we set at the beginning of the year. These objectives included: +• the generation of free cash flow in all four quarters of 2021; +• the net repayment of $340.0 million in borrowings under our revolving credit facility, resulting in outstanding borrowings of $100.0 million at December 31, 2021; +• the adoption of a dividend policy in the first quarter of 2021 pursuant to which we initiated a quarterly cash dividend of $0.025 per share of common stock and the subsequent amendment of that dividend policy in the fourth quarter of 2021, pursuant to which we doubled the quarterly cash dividend to $0.05 per share of common stock; and +• the receipt of $48.6 million in performance incentives directly from Five Point; +In addition, we concluded several important financing transactions in 2021 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the closing of our fourth amended and restated credit agreement (the “Credit Agreement”) in November 2021 to (i) extend the maturity date by three years to October 31, 2026 from October 31, 2023 previously, (ii) increase the borrowing base by 50% to $1.35 billion, as compared to $900.0 million previously, (iii) reaffirm the elected borrowing commitment at $700.0 million, (iv) reaffirm the maximum facility amount at $1.5 billion and (v) add three new banks to our lending group; and +• the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in June 2021 to increase the lender commitments under the revolving credit facility to $450.0 million from $375.0 million and an accordion feature that provides for potential increases in lender commitments to up to $700.0 million. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +San Mateo achieved strong operating results in 2021, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2020. Volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. +During 2021, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021. +At December 31, 2021, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity in San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large-diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 14 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +5 +Table of Contents +Environmental, Social and Governance (“ESG”) Initiatives +We maintain an active ESG program and continued working in 2021 to improve upon our various ESG efforts. In May 2021, we published sustainability metrics aligned with standards developed by the Sustainability Accounting Standards Board (“SASB”), which we subsequently updated in July 2021. In December 2021, we issued our inaugural Sustainability Report highlighting the results of our 2020 ESG progress and achievements. +In 2020, we grew gross operated oil production by 13% and gross operated natural gas production by 19%, as compared to 2019, while still reducing our environmental impact and continuing our strong safety record. Highlights from our 2020 ESG initiatives include: +• Decreased emissions intensity by 19% and flaring intensity by 38%, as compared to 2019; +• Decreased consumption of fresh water by 49%, as compared to 2019; +• Transported 96% of operated produced water and 65% of operated produced oil by pipeline; +• Incurred no employee lost time incidents during more than 2.1 million employee man-hours from 2017 to 2020; +• Provided approximately 15,000 hours of employee continuing education, equating to approximately 55 hours per employee; and +• Revised the mandate of the Board of Directors’ Environmental, Social and Corporate Governance Committee to enhance the focus, oversight and support for our ESG efforts and to measure improvements. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2021, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2021. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +237,200 124,800 944 468.1 4,381 1,534 312,018 58.6 80,534 +South Texas: +Eagle Ford (5) +27,400 25,100 131 110.5 208 175 5,663 100.0 2,126 +Northwest Louisiana +Haynesville 16,700 9,100 233 18.3 161 15 4,848 82.6 3,334 +Cotton Valley (6) +16,100 14,900 63 39.6 154 35 868 100.0 182 +Area Total (7) +19,100 17,700 296 57.9 315 50 5,716 85.3 3,516 +Total 283,700 167,600 1,371 636.5 4,904 1,759 323,397 59.8 86,176 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2021. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2021, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2021, these engineered drilling locations included 358 gross (136 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, in the Delaware Basin and only eight gross (0.4 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. At December 31, 2021, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +6 +Table of Contents +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2021. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. In January 2022, the two wells and associated acreage in Zavala County, Texas, which included 55 gross (55 net) engineered locations, were divested. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2021, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2021, we also were the operator for almost all of our Eagle Ford acreage and approximately half of our Haynesville acreage. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2021, our total acreage position in Southeast New Mexico and West Texas was approximately 237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 39,700 gross (22,600 net) acres in our Ranger asset area in Lea County, 64,500 gross (26,000 net) acres in our Arrowhead asset area in Eddy County, 47,500 gross (25,900 net) acres in our Rustler Breaks asset area in Eddy County, 24,700 gross (15,700 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,700 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 42,900 gross (20,500 net) acres in our Twin Lakes asset area in Lea County at December 31, 2021. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2021, our acreage position in the Delaware Basin was approximately 75% held by existing production. Excluding the Twin Lakes asset area, where at December 31, 2021 we had drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 86% held by existing production at December 31, 2021. +During the year ended December 31, 2021, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin, including 47 +7 +Table of Contents +gross (44.2 net) operated horizontal wells and 50 gross (4.0 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2021, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2021. Our average daily oil equivalent production from the Delaware Basin increased approximately 19% to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020. +At December 31, 2021, approximately 96% of our estimated total proved oil and natural gas reserves, or 312.0 million BOE, was attributable to the Delaware Basin, including approximately 177.1 million Bbl of oil and 809.3 Bcf of natural gas, a 19% increase, as compared to 261.9 million BOE for the year ended December 31, 2020. Our Delaware Basin proved reserves at December 31, 2021 comprised approximately 98% of our proved oil reserves and 95% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and 96% of our proved natural gas reserves at December 31, 2020. +At December 31, 2021, we had identified 4,381 gross (1,534 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,204 gross (1,350 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2021, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2021, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2021, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2021, these potential future drilling locations included 358 gross (136 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves. +At December 31, 2021, we were operating five drilling rigs in the Delaware Basin. At February 22, 2022, we had contracted a sixth drilling rig to begin drilling operations on recently acquired acreage in the western portion of our Ranger asset area in Lea County, New Mexico. We expect to operate six drilling rigs across our various Delaware Basin asset areas throughout the remainder of 2022, but these six drilling rigs are expected to have an increased focus on our Rustler Breaks, Antelope Ridge and Ranger asset areas in 2022, as compared to 2021. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2022. +Antelope Ridge Asset Area - Lea County, New Mexico +At the end of the first quarter of 2021, we achieved the first of the five operational milestones we set for Matador in 2021 when we turned to sales four gross (3.8 net) wells on the Rodney Robinson leasehold. These wells were the second group of wells drilled on the Rodney Robinson leasehold, which was acquired in the BLM Acquisition. We did not turn to sales any other operated wells in other portions of the Antelope Ridge asset area during 2021, although we did participate in the drilling and completion of 20 gross (1.1 net) non-operated wells that were turned to sales in the Antelope Ridge asset area during 2021. +The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. The four Rodney Robinson wells, which included two Wolfcamp A-XY completions and two Third Bone Spring +8 +Table of Contents +completions, were turned to sales late in the first quarter of 2021 and were all two-mile laterals. These four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in approximately 11 months of production despite being produced on restricted chokes throughout their early producing lives. We drilled nine additional Rodney Robinson wells in the fall of 2021, and these nine wells are expected to be turned to sales late in the first quarter of 2022. +We turned to sales the initial six Rodney Robinson wells in the western portion of the Antelope Ridge asset area in late March 2020. In aggregate, these six wells have produced approximately 4.3 million BOE in approximately 22 months of production. +Rustler Breaks Asset Area - Eddy County, New Mexico +In the Rustler Breaks asset area, we turned to sales 13 gross (0.9 net) non-operated wells during 2021. We did not turn to sales any operated wells during 2021, but at December 31, 2021, we had drilled or were drilling six operated wells in the Rustler Breaks asset area, all of which are expected to be turned to sales in the second quarter of 2022. We expect the Rustler Breaks asset area to be an area of increased operational focus for Matador throughout 2022. +Arrowhead Asset Area - Eddy County, New Mexico +In the Arrowhead asset area, we turned to sales 13 gross (11.5 net) operated wells and 14 gross (1.6 net) non-operated wells during 2021. +During the third quarter of 2021, we achieved the third of the five operational milestones we set for Matador in 2021 when we turned to sales four wells, all of which were two-mile laterals completed in the Second Bone Spring formation, in the Greater Stebbins Area. These four wells have produced in aggregate approximately 0.7 million BOE in seven months of production. At the end of the fourth quarter of 2021, we achieved the fifth and final operational milestone we set for Matador in 2021 when we turned to sales nine wells, all of which were two-mile laterals completed in the Third Bone Spring, Wolfcamp A-XY and Wolfcamp B formations, in the Greater Stebbins Area in December 2021. +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales two gross (1.3 net) operated wells and three gross (0.4 net) non-operated wells. We did not turn to sales any operated or non-operated wells in the Twin Lakes asset area during 2021. +We were pleased with the performance from the first two Uncle Ches wells turned to sales in the Second Bone Spring in the Ranger asset area in the first quarter of 2021. In aggregate, these two wells tested 4,053 BOE per day (90% oil) during 24-hour initial potential (“IP”) tests conducted after these wells were equipped with electric submersible pumps (“ESP”). The high (90%) oil cut and low water cut (approximately one Bbl of water per Bbl of oil produced) exhibited by these wells should enhance their economics. We drilled two additional Uncle Ches wells in the Ranger asset area in the fall of 2021, also Second Bone Spring completions, which were turned to sales in mid-January 2022. +Stateline Asset Area - Eddy County, New Mexico +We operated two drilling rigs in our Stateline asset area for the majority of 2021. In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,900 gross and net leasehold acres prospective for multiple geologic targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage has shown to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We have been developing this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.3-mile laterals on the western side of the leasehold. We began drilling operations in the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we turned to sales our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. In aggregate, the first 13 Boros wells have produced approximately 7.2 million BOE in approximately 15 months of production. +After finishing drilling operations on the first 13 Boros wells in 2020, we began drilling operations on the Voni tract in the western portion of the Stateline asset area, and in the second quarter of 2021, we achieved the second of the five operational milestones we set for Matador in 2021 when we turned to sales our first 13 gross (12.7 net) wells on the Voni tract in the western portion of the Stateline asset area. The 13 Voni wells had completed lateral lengths of approximately 12,000 feet, or about 2.3-miles, making them the longest laterals Matador has completed to date. The 13 Voni wells included one First Bone Spring completion, four Second Bone Spring completions, four Wolfcamp A-XY completions and four Wolfcamp A-Lower completions. Of particular note, the Voni Federal #216H well, a Wolfcamp A-Lower completion, tested 5,073 BOE per day (60% oil), which was the highest 24-hour IP Matador has achieved to date in any formation in the Delaware Basin. These 13 Voni wells have produced in aggregate approximately 5.2 million BOE in approximately eight months of production, despite a number of these wells being produced on restricted chokes early in their producing lives. +After finishing drilling operations on the first 13 Voni wells, we began drilling operations on the next 13 Boros wells, and in the third quarter of 2021, we achieved the fourth of the five operational milestones we set for Matador in 2021 when we +9 +Table of Contents +turned to sales our second group of 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. These 13 Boros wells have produced in aggregate approximately 2.2 million BOE in five months of production. Drilling and completion costs for the 26 Stateline wells turned to sales during 2021 averaged $628 per completed lateral foot, the lowest costs we have achieved in any of our asset areas. +In addition, during 2021, we drilled and completed our second group of 11 wells on the Voni tract on the western portion of the Stateline leasehold. These 11 Voni wells are expected to have completed lateral lengths of approximately 12,000 feet and were turned to sales in the first quarter of 2022. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we turned to sales two gross (1.9 net) operated wells during 2021. At December 31, 2021, we were in the process of completing three two-mile lateral wells in the Second Bone Spring formation, and these three wells were turned to sales in February 2022. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2021, our properties included approximately 27,400 gross (25,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2021. +We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2021. In fact, as of December 31, 2021, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 12% to 2,126 BOE per day, including 1,528 Bbl of oil per day and 3.6 MMcf of natural gas per day, during 2021, as compared to 2,412 BOE per day, including 1,840 Bbl of oil per day and 3.4 MMcf of natural gas per day, during 2020. For the year ended December 31, 2021, 2% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 3% for the year ended December 31, 2020. +At December 31, 2021, approximately 2% of our estimated total proved oil and natural gas reserves, or 5.7 million BOE, was attributable to the Eagle Ford shale, including approximately 4.1 million Bbl of oil and 9.1 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2021, essentially unchanged from December 31, 2020. +At December 31, 2021, we had identified 208 gross (175 net) engineered locations for potential future drilling on our Eagle Ford acreage, including 55 gross (55 net) engineered locations in Zavala County that were divested in January 2022. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to almost two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2021, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the prospectivity of these intervals. +10 +Table of Contents +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated Haynesville shale wells that were turned to sales in 2021. In the first quarter of 2020, we leased 2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained royalty interests ranging from 18% to 20%. This lessee turned to sales four Haynesville shale wells drilled on these interests in the first half of 2021. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2022. +At December 31, 2021, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including 16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,800 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2021. +For the year ended December 31, 2021, approximately 4% of our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 7% of our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2021, approximately 9% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 17% of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to these properties. At December 31, 2021, approximately 2% of our estimated total proved reserves, or 5.7 million BOE, was attributable to our properties in Northwest Louisiana. +At December 31, 2021, we had identified 161 gross (15 net) engineered locations for potential future drilling in the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to two miles, with most being two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other factors. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 22, 2022, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through February 22, 2022, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021, and we may earn up to the remaining $14.7 million in San Mateo performance incentives over the next year relating to the formation of San Mateo. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15- +11 +Table of Contents +year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of 2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives from Five Point. At February 22, 2022, we had received $33.9 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2021, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2021, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area. +In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2021, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2021, San Mateo gathered approximately 86.1 Bcf of natural gas, an increase of 17%, as compared to 73.9 Bcf of natural gas gathered during the year ended December 31, 2020. In addition, during the year ended December 31, 2021, San Mateo processed approximately 77.6 Bcf of natural gas at the Black River Processing Plant, an increase of 28%, as compared to 60.8 Bcf of natural gas processed during the year ended +12 +Table of Contents +December 31, 2020. Natural gas gathering and processing volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +In 2020, San Mateo completed and placed into service (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2021, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. +At December 31, 2021, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2021, the San Mateo Oil Pipeline Systems had throughput of approximately 14.9 million Bbl of oil, an increase of 28%, as compared to throughput of approximately 11.6 million Bbl of oil during the year ended December 31, 2020. +Produced Water Gathering and Disposal Assets +During 2021, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to three. In addition to its three commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 22, 2022, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 22, 2022, San Mateo had designed disposal capacity of approximately 370,000 Bbl of produced water per day. +During the year ended December 31, 2021, San Mateo handled approximately 101.4 million Bbl of produced water, an increase of 20%, as compared to approximately 84.8 million Bbl of produced water handled during the year ended December 31, 2020. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo. +13 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2021, 2020 and 2019. +Year Ended December 31, +2021 2020 2019 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 17,840 15,931 13,984 +Natural gas (Bcf) 81.7 69.5 61.1 +Total oil equivalent (MBOE) (1) +31,454 27,514 24,164 +Average daily production (BOE/d) (1) +86,176 75,175 66,203 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 67.58 $ 37.38 $ 54.34 +Oil, with realized derivatives (per Bbl) $ 56.70 $ 39.83 $ 54.98 +Natural gas, without realized derivatives (per Mcf) $ 6.06 $ 2.14 $ 2.17 +Natural gas, with realized derivatives (per Mcf) $ 5.74 $ 2.14 $ 2.18 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 5.69 $ 3.39 $ 3.82 +Lease operating $ 3.46 $ 3.81 $ 4.85 +Plant and other midstream services operating $ 1.95 $ 1.51 $ 1.52 +Depletion, depreciation and amortization $ 10.97 $ 13.15 $ 14.51 +General and administrative $ 3.06 $ 2.27 $ 3.31 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 17,279 558 — 3 17,840 +Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7 +Total oil equivalent (MBOE) (3) +29,395 776 1,217 66 31,454 +Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 47,339 1,528 — 9 48,876 +Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8 +Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176 +Average Sales Prices (4) +Oil (per Bbl) $ 67.65 $ 65.41 $ — $ 64.40 $ 67.58 +Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06 +Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 15,254 674 — 3 15,931 +Natural gas (Bcf) 56.8 1.2 11.0 0.5 69.5 +Total oil equivalent (MBOE) (3) +24,713 883 1,835 83 27,514 +Percentage of total annual net production 89.8 % 3.2 % 6.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 41,678 1,840 — 8 43,526 +Natural gas (MMcf/d) 155.1 3.4 30.1 1.3 189.9 +Total oil equivalent (BOE/d) 67,522 2,412 5,015 226 75,175 +Average Sales Prices (4) +Oil (per Bbl) $ 37.38 $ 37.42 $ 28.77 $ 38.31 $ 37.38 +Natural gas (per Mcf) $ 2.23 $ 2.82 $ 1.66 $ 1.69 $ 2.14 +Total oil equivalent (per BOE) $ 28.19 $ 32.56 $ 9.94 $ 11.09 $ 27.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.52 $ 20.52 $ 4.71 $ 19.39 $ 5.09 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 12,843 1,136 — 5 13,984 +Natural gas (Bcf) 44.7 2.0 13.9 0.5 61.1 +Total oil equivalent (MBOE) (3) +20,294 1,463 2,316 91 24,164 +Percentage of total annual net production 84.0 % 6.0 % 9.6 % 0.4 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 35,184 3,113 — 15 38,312 +Natural gas (MMcf/d) 122.5 5.4 38.1 1.4 167.4 +Total oil equivalent (BOE/d) 55,599 4,009 6,345 250 66,203 +Average Sales Prices (4) +Oil (per Bbl) $ 53.95 $ 58.71 $ — $ 52.89 $ 54.34 +Natural gas (per Mcf) $ 2.11 $ 3.45 $ 2.16 $ 2.17 $ 2.17 +Total oil equivalent (per BOE) $ 38.80 $ 50.22 $ 12.99 $ 15.22 $ 36.93 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.22 $ 15.27 $ 4.36 $ 22.43 $ 5.81 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021 increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31, 2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the year ended December 31, 2020. +Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020 increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31, 2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for the year ended December 31, 2019. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2021. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 81% in all wells that we operated at December 31, 2021. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +784 388.4 160 79.7 944 468.1 +South Texas: +Eagle Ford (2) +128 107.5 3 3.0 131 110.5 +Northwest Louisiana: +Haynesville — — 233 18.3 233 18.3 +Cotton Valley (3) +1 1.0 62 38.6 63 39.6 +Area Total 1 1.0 295 56.9 296 57.9 +Total 913 496.9 458 139.6 1,371 636.5 +__________________ +(1) Includes 212 gross (67.5 net) vertical wells that were acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2021, 2020 and 2019. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +17 +Table of Contents +At December 31, (1) +2021 2020 2019 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 181,306 159,949 147,991 +Natural Gas (Bcf) 852.5 662.3 627.2 +Total (MBOE) (3) +323,397 270,332 252,531 +Estimated proved developed reserves: +Oil (MBbl) 102,233 69,647 59,667 +Natural Gas (Bcf) 546.2 323.2 276.3 +Total (MBOE) (3) +193,262 123,507 105,710 +Percent developed 59.8 % 45.7 % 41.9 % +Estimated proved undeveloped reserves: +Oil (MBbl) 79,073 90,301 88,324 +Natural gas (Bcf) 306.4 339.1 351.0 +Total (MBOE) (3) +130,135 146,825 146,821 +Standardized Measure (4) (in millions) +$ 4,375.4 $ 1,584.4 $ 2,034.0 +PV-10 (5) (in millions) +$ 5,347.6 $ 1,658.0 $ 2,248.2 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas, for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas and for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2021, 2020 and 2019 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2021, 2020 and 2019 were, in millions, $972.2, $73.6 and $214.2, respectively. +Our estimated total proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. This increase in proved oil and natural gas reserves was primarily attributable to (i) our delineation and development operations in the Delaware Basin during 2021 and (ii) the 75% increase in oil prices and the 81% increase in natural gas prices used to estimate total proved reserves at December 31, 2021, as compared to December 31, 2020. We added 33.1 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 16.3 million BOE to proved reserves at a future date. We realized approximately 41.9 million BOE in net upward revisions to prior estimates, 96% of which were attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our properties. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our properties. In addition, we realized 9.5 million BOE in net upward revisions to our proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. +Our proved oil reserves grew 13% from approximately 159.9 million Bbl at December 31, 2020 to approximately 181.3 million Bbl at December 31, 2021. Our proved natural gas reserves increased 29% from 662.3 Bcf at December 31, 2020 to +18 +Table of Contents +852.5 Bcf at December 31, 2021. Our proved reserves to production ratio at December 31, 2021 was 10.3, an increase of 5% from 9.8 at December 31, 2020. +The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2021 were $63.04 per Bbl and $3.60 per MMBtu, an increase of 75% and 81%, respectively, as compared to average oil and natural gas prices of $36.04 per Bbl and $1.99 per MMBtu used to estimate proved reserves at December 31, 2020. Our total proved reserves were made up of 56% oil and 44% natural gas at December 31, 2021 and 59% oil and 41% natural gas at December 31, 2020. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2021. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2020 123,507 +Extensions and discoveries 22,427 +Net acquisitions of minerals-in-place 4,907 +Revisions of prior estimates 33,804 +Production (31,454) +Conversion of proved undeveloped to proved developed 40,071 +As of December 31, 2021 193,262 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 56% from 123.5 million BOE at December 31, 2020 to 193.3 million BOE at December 31, 2021. We added 22.4 million BOE in proved developed reserves through extensions and discoveries during 2021, which resulted from new well locations drilled during 2021 to establish proved reserves. We realized approximately 33.8 million BOE in net upward revisions to prior estimates, 97% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our producing properties. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our producing properties. In addition, we converted 40.1 million BOE of our proved undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. In addition, we realized 4.9 million BOE in net upward revisions to our proved developed reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. These cumulative net upward revisions of 101.2 million BOE to our proved developed reserves exceeded by 3.2 times our total oil and natural gas production of 31.5 million BOE in 2021. +Our proved developed oil reserves increased 47% from 69.6 million Bbl at December 31, 2020 to 102.2 million Bbl at December 31, 2021. Our proved developed natural gas reserves increased 69% from 323.2 Bcf at December 31, 2020 to 546.2 Bcf at December 31, 2021. Proved developed reserves constituted 60% of our total proved oil and natural gas reserves at December 31, 2021, as compared to 46% at December 31, 2020. +19 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2021. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2020 146,825 +Extensions and discoveries 10,647 +Net acquisitions of minerals-in-place 4,622 +Revisions of prior estimates 8,112 +Conversion of proved undeveloped to proved developed (40,071) +As of December 31, 2021 130,135 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at December 31, 2020 to 130.1 million at December 31, 2021. We added 26.9 million BOE in proved undeveloped reserves through extensions and discoveries during 2021, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2021 but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. We realized approximately 8.1 million BOE in net upward revisions to our prior estimates of proved undeveloped reserves, 90% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our proved undeveloped locations. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our proved undeveloped locations. In addition, we realized 4.6 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. During 2021, we also converted 40.1 million BOE of our proved undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. +At December 31, 2021, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2021 within five years of booking these reserves. The following table sets forth, since 2018, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2018 16,009 61.7 26,283 $ 356,830 +2019 13,832 58.8 23,629 318,609 +2020 16,256 76.1 28,944 257,590 +2021 23,965 96.6 40,071 240,664 +Total 70,062 293.2 118,927 $ 1,173,693 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +20 +Table of Contents +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2021. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 177,137 809.3 312,018 $ 4,268.7 $ 5,217.2 +South Texas: +Eagle Ford (5) +4,146 9.1 5,663 78.8 96.2 +Northwest Louisiana +Haynesville — 29.1 4,848 26.3 32.2 +Cotton Valley (6) +23 5.0 868 1.6 2.0 +Area Total 23 34.1 5,716 27.9 34.2 +Total 181,306 852.5 323,397 $ 4,375.4 $ 5,347.6 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2021 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2021 were approximately $972.2 million. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Reserves Manager was primarily responsible for overseeing the preparation of our reserves estimates in 2021. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional +21 +Table of Contents +Engineer in the state of Texas and has over nine years of industry experience. Our Reserves Manager works under the direct supervision of our Senior Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 14 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and U.S. generally accepted accounting principles (“GAAP”) requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2021. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 184,000 93,000 53,200 31,800 237,200 124,800 +South Texas: +Eagle Ford 27,400 25,100 — — 27,400 25,100 +Northwest Louisiana: +Haynesville 16,700 9,100 — — 16,700 9,100 +Cotton Valley 16,100 14,900 — — 16,100 14,900 +Area Total (1) +19,100 17,700 — — 19,100 17,700 +Total 230,500 135,800 53,200 31,800 283,700 167,600 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2021 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2027 and beyond totals 6,700 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2021. +Acres Acres Acres Acres Acres +Expiring 2022 Expiring 2023 Expiring 2024 Expiring 2025 Expiring 2026 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +24,100 11,100 5,500 5,300 8,900 3,100 2,900 2,800 5,200 2,800 +Total 24,100 11,100 5,500 5,300 8,900 3,100 2,900 2,800 5,200 2,800 +__________________ +(1) Approximately 65% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2021, +22 +Table of Contents +our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2021, less than 2% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2021, 2020 and 2019 . +Year Ended December 31, +2021 2020 2019 +Gross Net Gross Net Gross Net +Development Wells +Productive 96 40.2 89 44.5 147 62.0 +Dry — — — — — — +Exploration Wells +Productive 8 8.0 4 3.3 25 13.3 +Dry — — — — — — +Total Wells +Productive 104 48.2 93 47.8 172 75.3 +Dry — — — — — — +At December 31, 2021, we had a total of 31 gross (27.0 net) development wells and two gross (1.1 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, including Russia, Ukraine, China and the Middle East, domestic or global health concerns such as COVID-19, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in +23 +Table of Contents +the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2021, 2020 and 2019, we had three, two and two significant purchasers, respectively, that accounted for approximately 72%, 65% and 67%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals. Although some of these restrictions have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +24 +Table of Contents +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the Bureau of Land Management (“BLM”) to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). In 2019, 2020 and 2021, an environmental group filed three lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit, but the appeal was voluntarily dismissed in 2021. In February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. The BLM has not announced when it will complete the additional NEPA review, and the outcome of that review with regard to the leases at issue and any related drilling permits is uncertain. +25 +Table of Contents +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and gas leasing and permitting decisions by the BLM. In February 2022, the Louisiana federal district court issued an injunction prohibiting the federal government, including the Department of Interior and BLM, from utilizing the challenged social cost of greenhouse gases factor as a part of NEPA reviews. Subsequent to that decision, the federal government submitted filings in the federal district court indicating that the court’s injunction could, among other things, result in an indefinite delay of future lease sales and permit approvals due to inconsistencies between the NEPA analyses and the court’s ruling. +Although some of the restrictions in the Biden Administrative Federal Lease Orders have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation and Social Cost of Carbon Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing +26 +Table of Contents +regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. The Build Back Better Act (H.R. 5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains certain U.S. federal income tax changes and certain additional taxes and fees. +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +27 +Table of Contents +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures to protect the environment and work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (the “RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore +28 +Table of Contents +facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015 rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and the promulgation of the NWPR. +Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the U.S. Fish and Wildlife Service (the “USFWS”) under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance of NWPs in 2021. The Corps has now issued a new set of NWPs, which would replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but has not elected not to consult with the USFWS. The re-issued NWPs have similarly been subject to the same legal challenges based on the lack of a formal ESA consultation. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris +29 +Table of Contents +Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the New Mexico Oil Conservation Division (the “NMOCD”) implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) has also proposed similar rules and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our +30 +Table of Contents +ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have an adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +31 +Table of Contents +As of December 31, 2021, approximately 31% of our Delaware Basin acreage position consisted of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions related to the oil and natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2021, we had 286 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for +32 +Table of Contents +company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2020, for example, our employees completed approximately 15,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2021, we estimate our employees have worked approximately 2.7 million combined hours without experiencing a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations to proactively minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +33 +Table of Contents +Item 1A. Risk Factors. +Summary of Risk Factors +The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed risk factors contained below. +Risks Related to our Financial Condition +• Our success is dependent on the prices of oil and natural gas, the volatility of which may adversely affect our financial condition. +• We face numerous risks related to the COVID-19 global pandemic, including its impact on global oil demand. +• Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. +• Our oil and natural gas reserves are estimated and may not reflect the actual volumes we will recover, and we may be required to write down the carrying value of our proved properties under accounting rules. +• Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +• Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +• An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our financial condition. +• A component of our growth may come through acquisitions, which we may be unable to complete or which may require us to incur certain liabilities, risks or title deficiencies. +• Our ability to complete dispositions of assets may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +Risks Related to our Liquidity +• We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. +• The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +• The terms of the agreements governing our indebtedness impose significant operating and financial restrictions. +• Our credit rating may be downgraded, which could reduce our financial flexibility and increase interest expense. +• The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +Risks Related to our Operations +• Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational, geological and financial risk, and insurance against all such risks is not available to us. +• Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business. +• There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, and multi-well pad drilling may result in volatility in our operating results. +• Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. +• The unavailability or high cost of equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. +• We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. +34 +Table of Contents +• Regulatory changes could prevent our ability to continue to pool wells in the manner we have been. +• Midstream projects are subject to risks of construction delays and cost over-runs. +• Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter our plans. +Risks Related to Third Parties +• We depend upon several significant purchasers for the sale of most of our production, and financial difficulties encountered by such purchasers, other operators or third parties could decrease our cash flows from operations. +• The marketability of our production is dependent upon gathering, processing and transportation facilities. +• We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. +• Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products. +• We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput. +• Competition in our industry is intense, making it more difficult for us to acquire properties, market production, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources. +• We have limited control over activities on properties we do not operate. +Risks Related to Laws and Regulations +• As of December 31, 2021, approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations. +• We are subject to government regulation, including environmental laws, which could require significant expenditures. +• We are subject to tax laws, and changes thereto could eliminate or reduced certain federal income tax deductions or net operating loss carryforwards currently available. +• Legislative and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs, operating restrictions or delays. +• We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations, and the rates of our regulated assets are subject to oversight by regulators, which could adversely affect our revenues. +• Derivatives legislation adopted by Congress could limit our ability to hedge commodity price risks. +Risks Relating to Our Common Stock +• The price of our common stock is volatile and may fluctuate substantially in the future. +• Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect our stock price. +• Our directors and executive officers own a significant percentage of our equity, which could give them influence in transactions and other matters, and their interests could differ from other shareholders. +• Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +General Risk Factors +• We may have difficulty managing growth in our business. +• Our success depends on our ability to retain our key personnel. +• If we fail to maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. +• A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +• Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. +• We operate in a litigious environment and may be involved in legal proceedings that could have an adverse effect on our results of operations and financial condition. +35 +Table of Contents +Risks Related to our Financial Condition +Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations. +The prices we receive for the oil and natural gas we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34 per Bbl in 2020, ranging from a low of $47.62 per Bbl at the start of the year to a high of $84.65 per Bbl in October, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2021, natural gas prices averaged $3.71 per MMBtu, as compared to $2.13 per MMbtu in 2020, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2021, natural gas prices ranged from a low of $2.45 per MMBtu in January to a high of $6.31 per MMBtu in October before finishing the year at $3.73 per MMBtu. +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• the domestic and foreign supply of, and demand for, oil and natural gas; +• the actions of OPEC+ and state-controlled oil companies relating to oil price and production controls; +• the prices and availability of competitors’ supplies of oil and natural gas; +• the price and quantity of foreign imports; +• the impact of U.S. dollar exchange rates; +• domestic and foreign governmental regulations and taxes; +• speculative trading of oil and natural gas futures contracts; +• the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; +• the availability of refining capacity; +• the prices and availability of alternative fuel sources; +• weather conditions and natural disasters; +• political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19; +• the continued threat of terrorism and the impact of military action and civil unrest; +• public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; +• the level of global oil and natural gas inventories and exploration and production activity; +• the impact of energy conservation efforts; +• technological advances affecting energy consumption; and +• overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil and natural gas prices do not necessarily fluctuate in direct relation to each other. +Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our +36 +Table of Contents +midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +We face numerous risks related to the COVID-19 global pandemic, which has had and is likely to continue to have a material adverse effect on our business, financial condition, results of operations and cash flows. +Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which materially reduced global demand for crude oil. The extent to which COVID-19 will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information that may emerge concerning the severity of COVID-19 and the effectiveness of vaccines and other actions taken to contain COVID-19 or treat its impact now or in the future, among others. +Some impacts of the COVID-19 pandemic that could have an adverse effect on our business, financial condition, results of operations and cash flows include: +• significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production; +• further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result, in part, of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19; +• increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces; +• significant decreases in the volumes of oil, natural gas and produced water that are transported, gathered, processed or disposed of by San Mateo due to curtailed or shut-in production by Matador or other of San Mateo’s customers; +• increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate; +• increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints; +• the potential for the operations of the Black River Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 among the relevant workforce; +• the potential for forced curtailment of oil and natural gas production by state governmental agencies, resulting in a need to significantly curtail or shut in our production; +• the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing; +• increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage or the failure of certain of our counterparties to continue as going concerns; +• increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions; +• the potential impact for delays in construction or increased costs related to midstream construction projects; +• increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and +• increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations. +37 +Table of Contents +The COVID-19 outbreak continues to evolve, and the extent to which the outbreak may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired. +Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• our estimated proved oil and natural gas reserves; +• the amount of oil and natural gas we produce; +• the prices at which we sell our production; +• the costs of developing and producing our oil and natural gas reserves; +• the costs of constructing, operating and maintaining our midstream facilities; +• our ability to attract third-party customers for our midstream services; +• our ability to acquire, locate and produce new reserves; +• the ability and willingness of banks to lend to us; and +• our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak of contagious or pandemic diseases, financial market disruptions, general economic recessions, oil and natural gas industry recessions, oil and gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. +Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, +38 +Table of Contents +among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• the quality and quantity of available data; +• the interpretation of that data; +• the judgment of the persons preparing the estimate; and +• the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of certain of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• actual prices we receive for oil and natural gas; +• actual costs and timing of development and production expenditures; +• the amount and timing of actual production; and +• changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 44% of our total proved reserves at December 31, 2021 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +At December 31, 2021, approximately 40% of our total proved reserves were undeveloped and approximately 4% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and +39 +Table of Contents +industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have: +• downward adjustments to our estimated proved reserves; +• increases in our estimates of development costs; or +• deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021. +An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows. +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the +40 +Table of Contents +price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. +Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in 2020 and 2021, these price differentials could turn negative and widen again in future periods. Should we experience future periods of negative pricing for natural gas as we did at certain times in 2020, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. We have limited oil basis hedges in place to mitigate our exposure to oil price differentials during 2022, and we have no derivative contracts in place to mitigate our exposure to natural gas price differentials. +A component of our growth may come through acquisitions, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations. +Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We may not perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +41 +Table of Contents +We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost. +It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +Risks Related to our Liquidity +We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any +42 +Table of Contents +debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs. +As of February 22, 2022, the maximum facility amount under the Credit Agreement was $1.50 billion, the borrowing base was $1.35 billion and our elected borrowing commitment was $700.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenants noted below). At February 22, 2022, we had available borrowing capacity of approximately $554.2 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is defined as (x) consolidated current assets plus the unused availability under the Credit Agreement divided by (y) consolidated current liabilities less current maturities under the Credit Agreement, of equal to or greater than 1.0. +As of February 22, 2022, the facility amount under the San Mateo Credit Facility was $450.0 million, and San Mateo had available borrowing capacity of approximately $56.0 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $700.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. In addition to these restrictions, the San Mateo Credit Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• increasing our vulnerability to general adverse economic and industry conditions; +• placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• increasing the risk that we may default on our debt obligations. +The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, +43 +Table of Contents +respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 22, 2022, our borrowing base was $1.35 billion, our elected borrowing commitment was $700.0 million, the maximum facility amount under the Credit Agreement was $1.50 billion and we had $100.0 million in outstanding borrowings under, and approximately $45.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement. At February 28, 2022, we had repaid an additional $25.0 million, resulting in $75.0 million in borrowings outstanding under the Credit Agreement. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenant noted above). We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement), plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% per annum depending on the level of borrowings under the Credit Agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.75% to 2.75% per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +As noted above, under the Credit Agreement and the San Mateo Credit Facility, borrowings in the form of Eurodollar loans currently accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued. Each of the Credit Agreement and the San Mateo Credit Facility specify that the use of LIBOR as a global reference rate will, upon the occurrence of certain events, transition to a rate based on the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment. As a result, the interest rate for borrowings under the Credit Agreement and the San Mateo Credit Facility may be higher than an interest rate based solely on LIBOR. Each of the Credit Agreement and the San Mateo Credit Facility also specify that in the event that LIBOR and SOFR cannot be determined or other conditions exist with respect to LIBOR and SOFR, a replacement interest rate that gives due consideration to the then-prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time may be established by the respective administrative agents, in consultation with us. If such an event occurs and we are unable to agree upon a replacement interest rate with our respective administrative agents, we could be unable to make borrowings in the form of Eurodollar loans and would have to borrow funds at the higher base rate, which could increase our cost of capital. Furthermore, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR or the use of SOFR as a replacement for LIBOR. An increase in our cost of capital or a disruption in the financial market could have an adverse effect on our business and financial condition. +The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions. +Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• incur or guarantee additional debt or issue certain types of preferred stock; +44 +Table of Contents +• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• transfer or sell assets; +• make certain investments; +• create certain liens; +• enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• consolidate, merge or transfer all or substantially all of our assets; +• engage in transactions with affiliates; and +• create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is defined as current assets plus the unused availability under the Credit Agreement, divided by current liabilities, of equal to or greater than 1.0. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. +Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is defined as consolidated total funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations. +In March 2020, our corporate credit rating from S&P Global Ratings was downgraded from “B+” to “B-” and our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades resulted in significant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services subsequently upgraded our corporate credit rating to “B2” in July 2020 and to “B1” in September 2021. S&P Global Ratings upgraded our corporate credit rating to “B” in June 2021 and “B+” in January 2022. In September 2021, Fitch Ratings assigned us a corporate credit rating of “B+.” As of February 22, 2022, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “B+,” “B1” and “B+,” respectively. We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +Our Board of Directors declared a quarterly dividend of $0.025 per share of common stock in each of the first three quarters of 2021 and, in October 2021, the Board amended our dividend policy to increase the quarterly dividend and declared a +45 +Table of Contents +quarterly cash dividend of $0.05 per share of common stock. We intend to continue to pay a quarterly dividend in the future pursuant to a dividend policy adopted by our Board of Directors. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available. +We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price. +Risks Related to our Operations +Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• general economic and industry conditions, including the prices received for oil and natural gas; +• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• potential drainage of oil and natural gas from our properties by operations on adjacent properties; +• the existence or magnitude of faults or unanticipated geological features; +• loss of or damage to oilfield development and service tools; +• accidents, equipment failures or mechanical problems; +• title defects of the underlying properties; +• increases in severance taxes; +• adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• domestic and foreign governmental regulations; and +• proximity to and capacity of gathering, processing, transportation and disposal facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +46 +Table of Contents +• landing our wellbore in the desired drilling zone; +• staying in the desired drilling zone while drilling horizontally through the formation; +• running our casing the entire length of the wellbore; +• fracture stimulating the planned number of stages; +• drilling out the plugs between stages following hydraulic fracturing operations; and +• being able to run tools and other equipment consistently through the horizontal wellbore. +Each of these risks is magnified in wells with longer laterals. In 2021, 98% of the operated wells we turned to sales had lateral lengths of two miles or greater. In 2022, we anticipate that 90% of the operated wells we turn to sales should have lateral lengths of two miles or greater. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• natural disasters; +• adverse weather conditions; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19; +• loss of drilling fluid circulation; +• blowouts where oil or natural gas flows uncontrolled at a wellhead; +• cratering or collapse of the formation; +• pipe or cement leaks, failures or casing collapses; +• damage to pipelines, processing plants and disposal wells and associated facilities; +• fires or explosions; +• releases of hazardous substances or other waste materials that cause environmental damage; +• pressures or irregularities in formations; and +• equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. The protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production. In addition, if such a seismic event occurred in the area of San Mateo’s operations, San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. Any such events could adversely impact our and San Mateo’s revenues and cash flows. +There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Black River Processing Plant owned by San Mateo and operated by us. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. +47 +Table of Contents +Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected. +Insurance against all operational risks is not available to us. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 93% of our total oil and natural gas production for 2021 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2022 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, including in February 2021, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +48 +Table of Contents +Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows. +There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value. +As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows. +Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. +Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. +Multi-well pad drilling may result in volatility in our operating results. +We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. +The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows. +Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. Further, supply chain disruptions being experienced throughout the United States may +49 +Table of Contents +limit our ability to procure the necessary products and services for drilling and completing wells, which could cause delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. +If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could have a material adverse impact on our future production results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity. +From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of +50 +Table of Contents +risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions related to the natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our drilling locations on federal lands may not be drilled as scheduled. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. +At December 31, 2021, we had leasehold interests in approximately 25,100 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2027. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Risks Related to Third Parties +Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the years ended December 31, 2021, 2020 and 2019, we had three, two and two significant purchasers, respectively, that collectively accounted for approximately 72%, 65% and 67%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows. +In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate and from San Mateo’s customers. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their +51 +Table of Contents +share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. +The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2022. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows. +We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we have and may continue to enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for certain joint ventures and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows. +52 +Table of Contents +Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s control. Any decrease in supplies to its midstream facilities could adversely affect San Mateo’s business and operating results. +San Mateo’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2021, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $987.6 million over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural gas and to secure trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may +53 +Table of Contents +force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, Board of Directors and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +We have limited control over activities on properties we do not operate. +We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• the timing and amount of capital expenditures; +• the operator’s expertise and financial resources; +• the rate of production of reserves, if any; +• approval of other participants in drilling wells; and +• selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +Risks Related to Laws and Regulations +Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands. +At December 31, 2021, Matador held approximately 124,800 net leasehold and mineral acres in the Delaware Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 38,600 net acres, or about 31%, were on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can +54 +Table of Contents +take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements that may be implemented, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. The change in the presidential administration may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for: +• personal injuries; +• property damage; +• containment and clean-up of oil, produced water and other spills; +• venting, flaring or other emissions; +• management and disposal of hazardous materials; +• remediation, clean-up costs and natural resource damages; and +• other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have +55 +Table of Contents +changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA). +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Furthermore, we participate in candidate conservation agreements for the lesser prairie-chicken, the sand dune lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. Participation in such agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have an adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The Build Back Better Act (H.R. 5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains certain U.S. federal income tax changes, including a 15% corporate minimum tax imposed on net taxable income of certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending with the corporation’s current tax year. The passage of any legislation or any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final +56 +Table of Contents +rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands. These rules were rescinded by rule in December 2017; however, in January 2018, California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the rules. The Northern District of California upheld the rescission in 2020, but this decision was then appealed to the Ninth Circuit Court of Appeals. However, in October 2020, the U.S. District Court for the District of Wyoming found that the BLM exceeded its statutory authority and acted arbitrarily in promulgating the 2016 Waste Prevention Rule. The court ordered that the rule be vacated, except for certain severable provisions. This decision has been appealed to the Tenth Circuit Court of Appeals. +Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. At various times during his presidential campaign, President Biden indicated support for prohibitions of hydraulic fracturing on federal lands or outright. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Recently, bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders at the local, state or federal level could limit our operations. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. See “Business—Regulation— Environmental, Health and Safety Regulation.” +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the +57 +Table of Contents +imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could adversely impact our business, cash flows and results of operations and could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of alternative sources of energy. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has also proposed similar rules and regulations. The EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our Operations—If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory +58 +Table of Contents +programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain family foundations and sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders, limiting the issuance of federal drilling permits and other federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, promoting energy efficiency or the development and consumption of alternative forms of energy, or prohibiting or restricting oil and natural gas development activities in certain areas, have been and likely will be proposed and/or promulgated during the Biden administration. In addition, the Biden administration has already issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before 2050 is a critical priority, affirmed his administration’s desire to establish the United States as a leader in addressing climate change and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes. +New regulations on all emissions from our operations could cause us to incur significant costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. However, in October 2020, the U.S. District Court for the District of Wyoming found that the BLM exceeded its statutory authority and acted arbitrarily in promulgating the 2016 Waste Prevention Rule. The court ordered that the rule be vacated, except for certain severable provisions. This decision has been appealed to the Tenth Circuit Court of Appeals. If not withdrawn or significantly revised, these rules are expected to result in an increase to our operating costs and changes in our operations. In November 2021, the EPA also proposed new NSPS updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state +59 +Table of Contents +regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations. +We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. +The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System +60 +Table of Contents +does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +Risks Relating to Our Common Stock +The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2021, our stock price fluctuated between a high of $47.23 and a low of $12.02. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• declaration of dividends or adjustments to our dividend policy; +• speculation in the press or investment community; +• announcement or consummation of acquisitions, dispositions or joint ventures by us; +• public reaction to our operations or plans, press releases, announcements and filings with the SEC; +61 +Table of Contents +• the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; +• the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations, such as the Biden Administration Federal Lease Orders; +• sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19; +• the realization of any of the risk factors presented in this Annual Report; +• the recruitment or departure of key personnel; +• commencement of, involvement in or unfavorable resolution of litigation; +• the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• changes in market valuations of companies similar to ours; and +• domestic and international economic, legal and regulatory factors unrelated to our performance. +Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price. +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors have published ESG disclosure standards that companies in which they invest are expected to adopt or follow. Furthermore, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. +Certain other stakeholders have pressured commercial and investment banks and other capital providers to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale plays. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected. +Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and the interests of our directors and executive officers could differ from other shareholders. +As of February 22, 2022, our directors and executive officers beneficially owned approximately 6.5% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder +62 +Table of Contents +vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +General Risk Factors +We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team, the members of our Board and our special Board advisors, and the loss of any key personnel, Board member or special Board advisor could disrupt our business operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +If we fail to maintain effective internal control over financial reporting in the future, our ability to accurately report our financial results could be adversely affected. +As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management. +63 +Table of Contents +Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. +A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our supervisory control and data acquisition (SCADA) systems, control important processes and facilities that are critical to our operations. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. +While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities. +Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: +• authorization for our Board of Directors to issue preferred stock without shareholder approval; +• a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• the prohibition of cumulative voting in the election of directors; and +• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +We operate in a litigious environment and may be involved in legal proceedings that could have an adverse effect on our results of operations and financial condition. +Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +64 +Table of Contents +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows. +On November 4, 2019, we received a Notice of Violation and Finding of Violation from the EPA and a Notice of Violation from the NMED alleging violations of the CAA and New Mexico State Implementation Plan at certain of our operated locations in New Mexico. We have provided information to the EPA and NMED and are engaged in discussions regarding a resolution of the alleged violations. We believe it is remote that the resolution of this matter will have a material adverse impact on our financial condition, results of operations or cash flows. Resolution of the matter may result in monetary sanctions of more than $300,000. +Item 4. Mine Safety Disclosures. +Not applicable. +65 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 22, 2022, we had 118,043,776 shares of common stock outstanding held by approximately 335 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2021. +Equity Compensation Plan Information +Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1)(2) +2,248,984 $ 22.92 1,571,972 +Equity compensation plans not approved by security holders — — — +Total 2,248,984 $ 22.92 1,571,972 +__________________ +(1) Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). +(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board of Directors in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report. +66 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2016 through December 31, 2021, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +67 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2021, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2021 to October 31, 2021 — $ — — — +November 1, 2021 to November 30, 2021 2,051 39.55 — — +December 1, 2021 to December 31, 2021 4,321 38.26 — — +Total +6,372 $ 38.68 — — +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +68 +Table of Contents +Item 6. Selected Financial Data. +Not applicable. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the impact of the worldwide spread of COVID-19 on oil and natural gas demand, oil and natural gas prices and our business, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +For a comparison of our results of operations for the years ended December 31, 2020 and December 31, 2019, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 26, 2021. +Overview +We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +2021 Operational Highlights +We began 2021 operating three drilling rigs in the Delaware Basin, as we continued to focus on the exploration, delineation and development of our Delaware Basin acreage in Lea and Eddy Counties, New Mexico and Loving County, Texas. In March 2021, we added a fourth rig to our operated drilling program, and in August 2021, we began operating a fifth drilling rig on behalf of San Mateo for the purpose of drilling an additional salt water disposal well in the southern part of the Arrowhead asset area in Eddy County, New Mexico (the “Greater Stebbins Area”). In October 2021, following the conclusion of drilling operations on the salt water disposal well, we moved this rig to the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area in Lea County, New Mexico. We operated five drilling rigs in the Delaware Basin during the remainder of 2021. Despite the addition of the fifth operated drilling rig and the acceleration of 11 Voni well completions forward into the fourth quarter of 2021, we were able to achieve D/C/E capital expenditures for 2021 of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021. +During the year ended December 31, 2021, we completed and began producing oil and natural gas from 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated Haynesville shale wells that began producing in 2021. +The vast majority of our 2021 capital expenditures was directed to (i) the delineation and development of our leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to the installation of pumping units and other +69 +Table of Contents +facilities on certain of our Eagle Ford shale wells in South Texas and to our participation in several non-operated wells drilled and completed in the Haynesville shale in Northwest Louisiana throughout 2021. +Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended December 31, 2020. Our average daily oil production in 2021 of 48,876 Bbl of oil per day increased 12% from 43,526 Bbl of oil per day in 2020. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production of 223.8 MMcf per day in 2021 increased 18% from 189.9 MMcf per day in 2020. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production in the Haynesville shale where we had significantly less non-operated activity in 2020 and 2021 as compared to 2019. Oil production comprised 57% of our total production for the year ended December 31, 2021, as compared to 58% in 2020. +For the year ended December 31, 2021, our oil and natural gas revenues were $1.70 billion, an increase of 128% from oil and natural gas revenues of $744.5 million for the year ended December 31, 2020. Our oil revenues increased 102% to $1.21 billion, as compared to $595.5 million for the year ended December 31, 2020. The increase in oil revenues resulted from a significantly higher weighted average realized oil price of $67.58 per Bbl in 2021, as compared to $37.38 per Bbl in 2020, as well as the 12% increase in oil production for the year ended December 31, 2021 noted above. Our natural gas revenues increased 232% to $494.9 million, as compared to $149.0 million for the year ended December 31, 2020. The increase in natural gas revenues resulted from an almost three-fold increase in our weighted average realized natural gas price of $6.06 per Mcf in 2021, as compared to $2.14 per Mcf in 2020, and the 18% increase in our natural gas production noted above. +We reported net income attributable to Matador shareholders of approximately $585.0 million, or $4.91 per diluted common share, on a GAAP basis for the year ended December 31, 2021, as compared to a net loss of $593.2 million, or ($5.11) per diluted common share, for the year ended December 31, 2020. Adjusted EBITDA for the year ended December 31, 2021 was $1.05 billion, as compared to Adjusted EBITDA of $519.3 million for the year ended December 31, 2020. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data—Non-GAAP Financial Measures.” +At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, with a Standardized Measure of $4.38 billion and a PV-10 of $5.35 billion. At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, with a Standardized Measure of $1.58 billion and a PV-10 of $1.66 billion. Our estimated total proved reserves of 323.4 million BOE at December 31, 2021 represented a 20% year-over-year increase, as compared to 270.3 million BOE at December 31, 2020. Our estimated proved oil reserves of 181.3 million Bbl at December 31, 2021 increased 13%, as compared to 159.9 million Bbl at December 31, 2020, and our estimated proved natural gas reserves of 852.5 Bcf at December 31, 2021 increased 29%, as compared to 662.3 Bcf at December 31, 2020. Proved oil reserves comprised 56% of our total proved reserves at December 31, 2021, as compared to 59% at December 31, 2020. At December 31, 2021, 60% of our total proved reserves were proved developed reserves, as compared to 46% at December 31, 2020. +Our proved oil and natural gas reserves in the Delaware Basin increased 19% to 312.0 million BOE at December 31, 2021, as compared to 261.9 million BOE at December 31, 2020, primarily as a result of our ongoing delineation and development operations there. At December 31, 2021, approximately 96% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 13% to 177.1 million Bbl at December 31, 2021, as compared to 156.3 million Bbl at December 31, 2020, and our proved natural gas reserves in the Delaware Basin increased 28% to 809.3 Bcf, as compared to 633.5 Bcf at December 31, 2020. Proved oil reserves comprised 57% of our Delaware Basin total proved reserves at December 31, 2021, as compared to 60% at December 31, 2020. +At both December 31, 2021 and December 31, 2020, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.” +70 +Table of Contents +2021 Midstream Highlights +San Mateo achieved strong operating results in 2021, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2020. Volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2021 and 2020. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. +During 2021, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021. +At December 31, 2021, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 14 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +2022 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2022. In the second half of 2021, we added a fifth operated drilling rig in the Delaware Basin to drill a salt water disposal well on behalf of San Mateo. In October 2021, following the conclusion of drilling operations on the salt water disposal well, we began drilling oil and natural gas wells with this rig, and we plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our 2022 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2022 estimated capital expenditure budget consists of $640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially all of these 2022 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2022 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2022, including 90% with anticipated completed lateral lengths of two miles or greater. +71 +Table of Contents +At December 31, 2021, we had $48.1 million in cash (excluding restricted cash) and $554.2 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $700.0 million). Excluding any possible significant acquisitions, we expect to fund our 2022 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2022, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. +We may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position (as we did in 2020, 2021 and early 2022), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2022. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2022 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquisitions of producing properties, acreage and mineral interests and midstream assets for 2022. The aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. +72 +Table of Contents +Revenues +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2021 2020 2019 +Operating Data: +Revenues (in thousands): (1) +Oil $ 1,205,608 $ 595,507 $ 759,811 +Natural gas 494,934 148,954 132,514 +Total oil and natural gas revenues 1,700,542 744,461 892,325 +Third-party midstream services revenues 75,499 64,932 59,110 +Sales of purchased natural gas 86,034 41,742 74,769 +Lease bonus - mineral acreage — 4,062 1,711 +Realized (loss) gain on derivatives (220,105) 38,937 9,482 +Unrealized gain (loss) on derivatives 21,011 (32,008) (53,727) +Total revenues $ 1,662,981 $ 862,126 $ 983,670 +Net Production Volumes: (1) +Oil (MBbl) 17,840 15,931 13,984 +Natural gas (Bcf) 81.7 69.5 61.1 +Total oil equivalent (MBOE) (2) +31,454 27,514 24,164 +Average daily production (BOE/d) (2) +86,176 75,175 66,203 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 67.58 $ 37.38 $ 54.34 +Oil, with realized derivatives (per Bbl) $ 56.70 $ 39.83 $ 54.98 +Natural gas, without realized derivatives (per Mcf) $ 6.06 $ 2.14 $ 2.17 +Natural gas, with realized derivatives (per Mcf) $ 5.74 $ 2.14 $ 2.18 +________________ +(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020 +Oil and natural gas revenues . Our oil and natural gas revenues increased $956.1 million, or 128%, to $1.70 billion for the year ended December 31, 2021, as compared to $744.5 million for the year ended December 31, 2020. Our oil revenues increased $610.1 million, or 102%, to $1.21 billion for the year ended December 31, 2021, as compared to $595.5 million for the year ended December 31, 2020. This increase in oil revenues resulted from an 81% increase in the weighted average oil price realized for the year ended December 31, 2021 to $67.58 per Bbl, as compared to $37.38 per Bbl realized for the year ended December 31, 2020, and the 12% increase in our oil production to 17.8 million Bbl of oil for the year ended December 31, 2021, as compared to 15.9 million Bbl of oil for the year ended December 31, 2020. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $346.0 million, or 232%, to $494.9 million for the year ended December 31, 2021, as compared to $149.0 million for the year ended December 31, 2020. The increase in natural gas revenues was primarily attributable to the almost three-fold increase in the weighted average natural gas price realized for the year ended December 31, 2021 to $6.06 per Mcf, as compared to $2.14 per Mcf realized for the year ended December 31, 2020, and the 18% increase in our natural gas production to 81.7 Bcf for the year ended December 31, 2021, as compared to 69.5 Bcf for the year ended December 31, 2020. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production from our properties in the Haynesville shale. +Third-party midstream services revenues. Our third-party midstream services revenues increased $10.6 million, or 16%, to $75.5 million for the year ended December 31, 2021, as compared to $64.9 million for the year ended December 31, 2020. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $37.6 million for the year ended December 31, 2021, as compared to $30.1 million for the year ended December 31, 2020, (ii) an increase in our third-party oil gathering and transportation revenues to $10.2 million for the year ended December 31, 2021, as compared to $9.4 million for the year ended December 31, 2020, and (iii) an increase in third-party produced water handling revenues to $27.6 million for the year ended December 31, 2021, as compared to $25.5 million for the year ended December 31, 2020. +73 +Table of Contents +Sales of purchased natural gas. Our sales of purchased natural gas increased $44.3 million, or 106%, to $86.0 million for the year ended December 31, 2021, as compared to $41.7 million for the year ended December 31, 2020. This increase was primarily the result of the increase in realized natural gas prices and an increase in natural gas volumes sold during the year ended December 31, 2021. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at the Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of operations. +Lease bonus - mineral acreage. We did not lease any of our mineral acreage to third parties during the year ended December 31, 2021. Our lease bonus - mineral acreage revenues were $4.1 million for the year ended December 31, 2020. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests. +Realized (loss) gain on derivatives . Our realized net loss on derivatives was $220.1 million for the year ended December 31, 2021, as compared to a realized net gain of approximately $38.9 million for the year ended December 31, 2020. We realized a net loss of $197.5 million related to our oil costless collar and swap contracts for the year ended December 31, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $26.1 million related to our natural gas costless collar contracts for the year ended December 31, 2021, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $3.5 million from our oil basis swap contracts for the year ended December 31, 2021, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized a net gain of $35.1 million related to our oil costless collar, put and swap contracts for the year ended December 31, 2020, resulting primarily from oil prices that were below the floor prices of certain of our oil costless collar contracts and below the strike price of certain of our oil put and swap contracts. We realized a net gain of $3.8 million from our oil basis swap contracts for the year ended December 31, 2020, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized an average loss on our oil derivatives of approximately $10.88 per Bbl of oil produced during the year ended December 31, 2021, as compared to an average gain of $2.45 per Bbl of oil produced during the year ended December 31, 2020. We realized an average loss on our natural gas derivatives of approximately $0.32 per Mcf of natural gas produced during the year ended December 31, 2021, as compared to no gain or loss on our natural gas derivatives during the year ended December 31, 2020. Our total oil volumes hedged for the year ended December 31, 2021 represented 61% of our total oil production, as compared to 77% of our total oil production for the year ended December 31, 2020. Our total natural gas volumes hedged for the year ended December 31, 2021 represented 62% of our total natural gas production, as compared to 10% of our total natural gas production for the year ended December 31, 2020. +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $21.0 million for the year ended December 31, 2021, as compared to an unrealized loss of $32.0 million for the year ended December 31, 2020. During the year ended December 31, 2021, the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts increased from a net liability of approximately $35.9 million to a net liability of approximately $14.9 million, resulting in an unrealized gain on derivatives of approximately $21.0 million for the year ended December 31, 2021. During the year ended December 31, 2020, the aggregate net fair value of our open oil and natural gas derivative and oil basis swap contracts decreased from a net liability of approximately $3.9 million to a net liability of $35.9 million, resulting in an unrealized loss on derivatives of approximately $32.0 million for the year ended December 31, 2020. +74 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2021 2020 2019 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing $ 178,987 $ 93,338 $ 92,273 +Lease operating 108,964 104,953 117,305 +Plant and other midstream services operating 61,459 41,500 36,798 +Purchased natural gas 77,126 32,734 69,398 +Depletion, depreciation and amortization 344,905 361,831 350,540 +Accretion of asset retirement obligations 2,068 1,948 1,822 +Full-cost ceiling impairment — 684,743 — +General and administrative 96,396 62,578 80,054 +Total expenses 869,905 1,383,625 748,190 +Operating income 793,076 (521,499) 235,480 +Other income (expense): +Net loss on asset sales and inventory impairment (331) (2,832) (967) +Interest expense (74,687) (76,692) (73,873) +Other (expense) income (2,712) 1,864 (2,126) +Total other (expense) income (77,730) (77,660) (76,966) +Income (loss) before income taxes 715,346 (599,159) 158,514 +Total income tax provision (benefit) 74,710 (45,599) 35,532 +Net income attributable to non-controlling interest in subsidiaries (55,668) (39,645) (35,205) +Net income (loss) attributable to Matador Resources Company shareholders $ 584,968 $ (593,205) $ 87,777 +Expenses per BOE: +Production taxes, transportation and processing $ 5.69 $ 3.39 $ 3.82 +Lease operating $ 3.46 $ 3.81 $ 4.85 +Plant and other midstream services operating $ 1.95 $ 1.51 $ 1.52 +Depletion, depreciation and amortization $ 10.97 $ 13.15 $ 14.51 +General and administrative $ 3.06 $ 2.27 $ 3.31 +Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020 +Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $85.6 million, or 92%, to $179.0 million for the year ended December 31, 2021, as compared to $93.3 million for the year ended December 31, 2020. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 68% to $5.69 per BOE for the year ended December 31, 2021, as compared to $3.39 per BOE for the year ended December 31, 2020. These increases were primarily attributable to the $76.5 million increase in our production taxes to $129.8 million for the year ended December 31, 2021, as compared to $53.4 million for the year ended December 31, 2020, resulting from the $956.1 million increase in oil and natural gas revenues for the year ended December 31, 2021, as compared to the year ended December 31, 2020 and the $9.2 million increase in transportation and processing expenses to $49.2 million for the year ended December 31, 2021, as compared to $40.0 million for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production between the respective periods. +Lease operating expenses. Our lease operating expenses increased $4.0 million, or 4%, to $109.0 million for the year ended December 31, 2021, as compared to $105.0 million for the year ended December 31, 2020. This increase in our lease operating expenses for the year ended December 31, 2021 was attributable to an increase in workover expenses of $4.0 million, which resulted from additional well maintenance operations conducted during the year-ended December 31, 2021, as compared to 2020. On a unit-of-production basis, our lease operating expenses decreased 9% to $3.46 per BOE for the year ended December 31, 2021, as compared to $3.81 per BOE for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production between the respective periods. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $20.0 million, or 48%, to $61.5 million for the year ended December 31, 2021, as compared to $41.5 million for the year ended December 31, 2020. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of $30.8 million for the year ended December 31, 2021, as compared to $21.8 million for the year ended December 31, 2020, (ii) increased expenses associated with our expanded pipeline operations of +75 +Table of Contents +$17.5 million for the year ended December 31, 2021, as compared to $10.0 million for the year ended December 31, 2020, and (iii) increased expenses associated with operating the Black River Processing Plant of $13.1 million for the year ended December 31, 2021, as compared to $9.7 million for the year ended December 31, 2020. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $16.9 million, or 5%, to $344.9 million for the year ended December 31, 2021, as compared to $361.8 million for the year ended December 31, 2020. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 17% to $10.97 per BOE for the year ended December 31, 2021, as compared to $13.15 per BOE for the year ended December 31, 2020. These decreases were primarily attributable to the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded during the year ended December 31, 2020. These decreases were partially offset by (i) the 14% increase in total oil equivalent production to 31.5 million BOE for the year ended December 31, 2021, as compared to 27.5 million BOE for the year ended December 31, 2020, and (ii) increased depreciation expenses attributable to our midstream segment of approximately $31.5 million for the year ended December 31, 2021, as compared to $23.3 million for the year ended December 31, 2020. +Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the year ended December 31, 2021. Due to the sharp decline in oil and natural gas prices used to estimate proved oil and natural gas reserves in 2020, at June 30, 2020, September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an impairment charge of $684.7 million, exclusive of tax effect, to our net capitalized costs. This full-cost ceiling impairment is reflected in our consolidated statement of operations for the year ended December 31, 2020, with the related deferred income tax credit recorded net of a valuation allowance. +General and administrative. Our general and administrative expenses increased $33.8 million, or 54%, to $96.4 million for the year ended December 31, 2021, as compared to $62.6 million for the year ended December 31, 2020. Our general and administrative expenses on a unit-of-production basis increased 35% to $3.06 per BOE for the year ended December 31, 2021, as compared to $2.27 per BOE for the year ended December 31, 2020. These increases were largely attributable to employee compensation costs, including a $16.1 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period based upon our share price at the end of each reporting period. The share price of our common stock increased from $12.06 at December 31, 2020 to $36.92 at December 31, 2021. The remainder of the increase for the year ended December 31, 2021, as compared to December 31, 2020, resulted primarily from the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time. +Interest expense. For the year ended December 31, 2021, we incurred total interest expense of approximately $79.5 million. We capitalized approximately $4.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2021 and expensed the remaining $74.7 million to operations. For the year ended December 31, 2020, we incurred total interest expense of approximately $82.2 million. We capitalized $5.5 million of our interest expense on certain qualifying projects for the year ended December 31, 2020 and expensed the remaining $76.7 million to operations. +Total income tax provision (benefit). At December 31, 2020, our deferred tax assets exceeded our deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, we established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. Due to a variety of factors, including our significant net income in 2021, our federal valuation allowance was reversed at September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of our state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. We recorded a total income tax provision of $74.7 million for the year ended December 31, 2021. Our effective tax rate was 11.3% for the year ended December 31, 2021, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of reversing the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a total income tax benefit of $45.6 million for the year ended December 31, 2020. Our effective tax rate was 7.6% for the year ended December 31, 2020, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico. +76 +Table of Contents +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2022 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditures for 2022 primarily through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2022, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. +At December 31, 2021, we had cash totaling $48.1 million and restricted cash totaling $38.8 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +At December 31, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $100.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration (“SBA”) loan. In November 2021, the Company and lenders under our Credit Agreement entered into a Fourth Amended and Restated Credit Agreement, under which the borrowing base was increased to $1.35 billion. We elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and certain modifications were made to the terms of the Credit Agreement. These modifications include extending the maturity date to October 31, 2026, increasing the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50% and updating the key financial covenants under the Credit Agreement to require the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter, and (ii) a debt to EBITDA ratio, which is defined as total debt outstanding (net of up to $75.0 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less. This November 2021 update to the Credit Agreement took the place of the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenants noted above). We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2021. Between December 31, 2021 and February 28, 2022, we repaid an additional $25.0 million of borrowings outstanding under the Credit Agreement. +At December 31, 2021, San Mateo had $385.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under that facility from $375 million to $450 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility contains an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million. The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2021. Between December 31, 2021 and February 22, 2022, we repaid an additional $30.0 million of borrowings outstanding under the San Mateo Credit Facility. +77 +Table of Contents +On April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately $7.5 million as part of the Paycheck Protection Program. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act and is administered by the SBA. The loan was issued through Iberiabank, which is a lender under the Credit Agreement, matures on the second anniversary of the funding date and bears interest at a fixed rate of 1.00% per a nn um. We used the proceeds of the loan for payroll, including salaries, payroll taxes and employee medical benefits, as permitted by the program. The receipt of the loan allowed us to avoid further reductions to employee headcount and salaries above those taken in March 2020. The loan is eligible for forgiveness for the portion of the loan proceeds used for payroll costs and other designated operating expenses, provided at least 60% of the loan’s proceeds are used for payroll costs. During 2021, we applied to the SBA for forgiveness of the Paycheck Protection Program loan, as all proceeds were used for payroll costs. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2022. In the second half of 2021, we added a fifth contracted drilling rig in the Delaware Basin and plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2022 estimated capital expenditure budget consists of $640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially all of these 2022 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, as well as amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2022 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2022, including 90% with anticipated completed lateral lengths of two miles or greater. +We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests, principally in the Delaware Basin, during 2022. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2022 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests for 2022. +Our 2022 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2022 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2022 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021. See “Risk +78 +Table of Contents +Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our cash flows for the years ended December 31, 2021, 2020 and 2019 are presented below. +Year Ended December 31, +2021 2020 2019 +(In thousands) +Net cash provided by operating activities $ 1,053,355 $ 477,582 $ 552,042 +Net cash used in investing activities (729,265) (775,666) (903,976) +Net cash (used in) provided by financing activities (328,553) 324,339 333,078 +Net change in cash $ (4,463) $ 26,255 $ (18,856) +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ 1,051,973 $ 519,277 $ 610,756 +__________________ +(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. +Cash Flows Provided by Operating Activities +Net cash provided by operating activities increased by $575.8 million to $1.05 billion for the year ended December 31, 2021, as compared to net cash provided by operating activities of $477.6 million for the year ended December 31, 2020. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $1.05 billion for the year ended December 31, 2021 from $500.7 million for the year ended December 31, 2020. This increase was primarily attributable to significantly higher realized oil and natural gas prices for the year ended December 31, 2021, as compared to the year ended December 31, 2020, as well as the 14% increase in total oil equivalent production during 2021, as compared to 2020. Changes in our operating assets and liabilities between December 31, 2020 and December 31, 2021 resulted in a net increase of approximately $22.1 million in net cash provided by operating activities for the year ended December 31, 2021, as compared to the year ended December 31, 2020. +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. For example, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods, particularly in 2020. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities decreased by $46.4 million to $729.3 million for the year ended December 31, 2021 from $775.7 million for the year ended December 31, 2020. This decrease in net cash used in investing activities was primarily attributable to a decrease of $40.0 million in D/C/E capital expenditures as compared to the year ended December 31, 2020, and a decrease of approximately $171.0 million in expenditures for midstream support equipment and facilities, resulting from completing the construction of the further expansion of the Black River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline infrastructure during 2020. These decreases were partially offset by an increase of $165.8 million in expenditures primarily related to our acquisition of oil and natural gas properties in the +79 +Table of Contents +Delaware Basin during 2021. Cash used for D/C/E capital expenditures for the year ended December 31, 2021 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin. +Cash Flows (Used in) Provided by Financing Activities +Net cash used in financing activities was $328.6 million for the year ended December 31, 2021, as compared to net cash provided by financing activities of $324.3 million for the year ended December 31, 2020. The net cash used in financing activities for the year ended December 31, 2021 was primarily attributable to (i) net repayments under our Credit Agreement of $340.0 million, (ii) net borrowings under the San Mateo Credit Facility of $51.0 million, (iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $13.4 million and (iv) dividends paid of $14.6 million. +See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes. +Guarantor Financial Information +The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2021, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes. +The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities. +(in thousands) +Summarized Balance Sheet December 31, 2021 +Assets +Current assets $ 305,712 +Net property and equipment $ 3,060,233 +Other long-term assets $ 48,890 +Liabilities +Current liabilities $ 461,013 +Long-term debt $ 1,142,580 +Other long-term liabilities $ 138,010 +(in thousands) Year Ended +Summarized Statement of Operations December 31, 2021 +Revenues $ 1,543,420 +Expenses 873,037 +Operating income $ 670,383 +Other expense (67,823) +Tax provision (74,710) +Net income $ 527,850 +Non-GAAP Financial Measures +We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +80 +Table of Contents +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2021 2020 2019 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net income (loss) attributable to Matador Resources Company shareholders $ 584,968 $ (593,205) $ 87,777 +Net income attributable to non-controlling interest in subsidiaries 55,668 39,645 35,205 +Net income (loss) 640,636 (553,560) 122,982 +Interest expense 74,687 76,692 73,873 +Total income tax provision (benefit) 74,710 (45,599) 35,532 +Depletion, depreciation and amortization 344,905 361,831 350,540 +Accretion of asset retirement obligations 2,068 1,948 1,822 +Full-cost ceiling impairment — 684,743 — +Unrealized (gain) loss on derivatives (21,011) 32,008 53,727 +Non-cash stock-based compensation expense 9,039 13,625 18,505 +Net loss on asset sales and impairment 331 2,832 967 +Expense related to contingent consideration 1,485 — — +Consolidated Adjusted EBITDA 1,126,850 574,520 657,948 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (74,877) (55,243) (47,192) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 1,051,973 $ 519,277 $ 610,756 +Year Ended December 31, +2021 2020 2019 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by +Operating Activities: +Net cash provided by operating activities $ 1,053,355 $ 477,582 $ 552,042 +Net change in operating assets and liabilities 982 23,078 34,517 +Interest expense, net of non-cash portion 71,028 73,860 71,389 +Expense related to contingent consideration 1,485 — — +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (74,877) (55,243) (47,192) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 1,051,973 $ 519,277 $ 610,756 +For the year ended December 31, 2021, we reported net income attributable to Matador shareholders of $585.0 million, as compared to a net loss attributable to Matador shareholders of $593.2 million for the year ended December 31, 2020. This increase primarily resulted from (i) significantly higher realized oil and natural gas prices and higher oil and natural gas production, for the year ended December 31, 2021, as compared to the year ended December 31, 2020, and (ii) no full-cost ceiling impairment recorded for the year ended December 31, 2021, as compared to $684.7 million recorded for the year ended December 31, 2020. These increases were partially offset by a realized loss on derivatives of $220.1 million for the year ended December 31, 2021, as compared to a realized gain on derivatives of $38.9 million for the year ended December 31, 2020, and an income tax provision of $74.7 million for the year ended December 31, 2021, as compared to an income tax benefit of $45.6 million for the year ended December 31, 2020. +81 +Table of Contents +Adjusted EBITDA, a non-GAAP financial measure, increased $532.7 million to $1.05 billion for the year ended December 31, 2021, as compared to $519.3 million for the year ended December 31, 2020. This increase was primarily attributable to the significantly higher realized oil and natural gas prices and higher oil and natural gas production noted above for the year ended December 31, 2021, as compared to the year ended December 31, 2020. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2021, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2021. +Payments Due by Period +Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years +(In thousands) +Contractual Obligations: +Borrowings, including letters of credit (1) +$ 547,273 $ — $ 401,470 $ 145,803 $ — +Senior unsecured notes (2) +1,050,000 — — 1,050,000 — +Office leases 18,483 4,123 8,529 5,831 — +Non-operated drilling and other capital commitments (3) +65,414 45,614 19,800 — — +Drilling rig contracts (4) +10,835 10,835 — — — +Asset retirement obligations (5) +41,959 270 5,074 1,518 35,097 +Transportation, gathering, processing and disposal agreements with non-affiliates (6) +597,334 70,014 143,424 142,185 241,711 +Transportation, gathering, processing and disposal agreements with San Mateo (7) +390,307 — 100,101 182,740 107,466 +Total contractual cash obligations $ 2,721,605 $ 130,856 $ 678,398 $ 1,528,077 $ 384,274 +__________________ +(1) The amounts included in the table above represent principal maturities only. At December 31, 2021, we had $100.0 million of borrowings outstanding under the Credit Agreement, approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million in borrowings under the SBA loan. The Credit Agreement matures in October 2026. At December 31, 2021 San Mateo had $385.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of 1.85% and 2.11%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at December 31, 2021, the interest expense for such facilities is expected to be approximately $1.9 million and $8.2 million each year until maturity. +(2) The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of December 31, 2021 is expected to be approximately $61.7 million each year until maturity. +(3) At December 31, 2021, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. +(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2021. +(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments. +(7) We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced +82 +Table of Contents +water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, political instability in Russia, Ukraine, China and the Middle East, the actions of OPEC+, the worldwide spread of COVID-19, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. +The prices we receive for oil, natural gas and NGLs heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically, and, as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the leverage ratio covenant under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) the increase in global oil supply resulting from the actions of OPEC+. The sudden decline in oil prices began to improve later in the second quarter of 2020 and generally continued throughout the remainder of 2020. +During the year ended December 31, 2021 and through February 22, 2022, the oil and natural gas industry experienced continued improvement in commodity prices, as compared to 2020, primarily resulting from (x) improvements in oil demand as the impact from COVID-19 has begun to abate, (y) actions taken by OPEC+ to reduce the worldwide supply of oil through coordinated production cuts and (z) changes in supply and demand dynamics, particularly with respect to natural gas markets generally and, more recently, instability in Russia and Ukraine. While oil and natural gas prices improved significantly in 2021 and early 2022, the general outlook for the oil and natural gas industry for the remainder of 2022 remains unclear, and we can provide no assurances that commodity prices will remain at current levels or increase further. In fact, commodity prices may decline from their current levels, particularly in response to the spread of new variants, if any, of COVID-19, the actions of OPEC+ and other governmental authorities to increase the global oil supply and milder weather conditions, among other factors. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations” in this Annual Report. The economic disruptions associated with COVID-19 and the volatility in oil and natural gas prices have also impacted our ability to access the capital markets on reasonably similar terms as were available prior to 2020. +For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34 per Bbl in 2020, ranging from a low of $47.62 per Bbl in early January to a high of $84.65 per Bbl in late October, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $67.58 per Bbl ($56.70 per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2021, as compared to $37.38 per Bbl ($39.83 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2020. At February 22, 2022, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2021, closing at $92.35 per Bbl, and was higher compared to $61.49 per Bbl on February 22, 2021. We are uncertain that oil prices will remain at these levels as noted above. +Natural gas prices also improved significantly during 2021. For the year ended December 31, 2021, natural gas prices averaged $3.71 per MMBtu, as compared to $2.13 per MMBtu in 2020, ranging from a low of $2.45 per MMBtu in late January to a high of $6.31 per MMBtu in early October. As a result of milder-than-expected winter weather, natural gas prices declined over the course of the fourth quarter of 2021, finishing the year at $3.73 per MMBtu. We realized a weighted average natural gas price of $6.06 per Mcf ($5.74 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2021, as compared to $2.14 per Mcf (with no realized gains or losses from natural gas derivatives) for the year ended December 31, 2020. As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average natural gas price. At February 22, 2022, the NYMEX Henry Hub natural gas futures +83 +Table of Contents +contract price for the earliest delivery date had increased from year-end 2021, closing at $4.50 per MMBtu, and was higher as compared to $2.95 per MMBtu at February 22, 2021. We are uncertain that natural gas prices will remain at these levels, particularly as we exit the winter heating season. +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2021, we incurred realized losses on our oil and natural derivative contracts of approximately $220.1 million, primarily as a result of oil and natural prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts and above the strike price of certain of our oil swap and oil basis swap contracts. At February 22, 2022, almost all of the derivative contracts we had in place that contributed to these realized losses on derivatives in 2021 had expired. At February 22, 2022, given current oil and natural gas prices and the oil and natural gas derivative contracts we have in place, we do not anticipate losses of such magnitude from our derivative contracts in 2022, although there may be periods where we realize losses from derivatives. At December 31, 2021, adjusted for derivative contracts entered into between January 1, 2022 and February 22, 2022, we had derivative contracts in place for approximately 5.1 million Bbl of our anticipated full year 2022 oil production and approximately 54.7 Bcf of our anticipated full year 2022 natural gas production. +The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2021, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas. +The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years but began 2020 slightly positive to the WTI oil price and remained positive through much of the first quarter. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive later in the second quarter and improving throughout the rest of 2020 and 2021 and into early 2022. At February 22, 2022, this oil price differential was approximately +$1.00 per Bbl. At February 22, 2022, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated full year 2022 oil production. +Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years, including times in April 2019 when natural gas was being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. In early 2020, the Waha basis differential remained significant at about ($1.20) per MMBtu and continued to deteriorate. Natural gas prices at the Waha hub were negative again on certain days in April 2020. The Waha basis differential narrowed during the remainder of the second quarter of 2020. During the third quarter of 2020 and, in particular, at the beginning of October 2020, the Waha basis differential widened significantly again, including several days when natural gas was being sold at the Waha hub for negative prices, due to seasonal pipeline maintenance and other factors that reduced capacity out of the Waha hub. These capacity issues have been largely resolved and the Waha basis differential improved during the remainder of 2020 and 2021. In early 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin, particularly beginning in the latter half of 2022, began to increase. As a result, the Waha basis differential began to widen, and, at February 22, 2022, this natural gas price differential was approximately ($0.60) per MMBtu. +A significant portion of our Delaware Basin natural gas production is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2021, we typically realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 11% of our reported natural gas production for the year ended December 31, 2021 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. +Although the natural gas price differentials have recently at times been positive or close to zero, these price differentials could deteriorate in future periods. Should we experience future periods of negative pricing for natural gas as we have in previous periods, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials in 2022. +84 +Table of Contents +At February 22, 2022, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain periods over the last few years, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +As a result of the recent increases in oil and natural gas prices, we have begun to experience inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, personnel and completion costs, among others. Should oil and natural gas prices remain at their current levels or increase further, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. We budgeted a 10 to 15% increase in oilfield service costs, as compared to the fourth quarter of 2021, in preparing our full-year D/C/E and midstream capital expenditures for 2022. Should we experience service cost inflation above 10 to 15% during 2022, we may be required to increase our 2022 estimated capital expenditure budget. Further, in early 2022, supply chain disruptions being experienced throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely fashion, which could result in delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows. +In addition, should oil and natural gas prices remain at their current levels throughout 2022, we may exhaust our federal or state net operating loss carryforwards and become subject to federal and state income taxes in future periods. At February 22, 2022, given our current projections, we do not expect to pay significant federal income taxes, if any, in 2022, but may pay federal income taxes in 2023. We may pay state income taxes in 2022 and 2023, however, in New Mexico and Texas. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has proposed similar rules and regulations. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our 2022 and future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to +85 +Table of Contents +impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well. See “Risk Factors—Risks Related to Laws and Regulations—The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.” +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Equity returns in the sector prior to 2021 versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.” +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2021. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the +86 +Table of Contents +amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” +Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with +87 +Table of Contents +guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently as an unrealized gain or loss on derivatives in our consolidated statements of operations. Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +Stock-Based Compensation +We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock. +We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on the date of the grant for awards issued under the 2012 Incentive Plan and on the trading day prior to the date of grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2021. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a +88 +Table of Contents +call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2021, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2021, we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of the costless collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +At December 31, 2021, we had entered into various swap contracts to mitigate our exposure to oil price differences between NYMEX WTI Cushing and Argus WTI Midland crude oil. When the settlement price is below the fixed price established by one or more of these basis swaps, we receive from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by one or more of these basis swaps, we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. +See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021. Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors—Risks Related to Laws and Regulations—The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt. At December 31, 2021, we had outstanding borrowings of $100.0 million at an interest rate of 1.85% per annum under our Credit Agreement, $1.05 billion in Notes outstanding at a coupon rate of 5.875% per annum and $385.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 2.11% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo is subject to the credit risk of its customers. The inability or failure of our or San Mateo’s significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the +89 +Table of Contents +customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 22, 2022 were The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), PNC Bank, Royal Bank of Canada and Truist Bank (or affiliates thereof), and all but BMO Harris Financing were lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement. +Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2021, 2020 and 2019. Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and has become much more significant in recent months, reaching its highest levels in approximately 40 years. At February 22, 2022, we do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward. We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. We have begun to experience such inflationary pressure in our drilling and completion and midstream operations, and we budgeted a 10 to 15% increase in oil field service costs, as compared to the fourth quarter of 2021, in preparing our full year 2022 D/C/E and midstream capital expenditures estimates. See “Risk Factors—Risks Related to our Operations—The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report beginning on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2021 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2021, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2021 as included herein. +90 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2022 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 28, 2022 +92 +Table of Contents +Item 9B. Other Information. +Not applicable. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2022 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 3—Ratification of Appointment of KPMG LLP.” +93 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2021 and 2020, Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019. +2. Financial Statement Schedules : All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto. +3. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below. +Item 16. Form 10-K Summary. +None. +94 +Table of Contents +EXHIBIT INDEX +Exhibit +Number Description +2.1 +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).* +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018). +4.3 +First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018). +4.4 +Second Supplemental Indenture, dated as of December 14, 2021, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N. A., as agent for Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on December 14, 2021). +4.5 +Description of Capital Stock (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2019). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.4† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.5† +First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.7† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.8† +Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +95 +Table of Contents +10.9† +Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.10† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.11† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.12† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.13† +First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.14† +First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.15† +Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.16† +First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.17† +Second Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson ( incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2020 ). +10.18† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.19 +Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). +10.20 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.21 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.22 +First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.23 +Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). +10.24 +Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). +96 +Table of Contents +10.25 +Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.26 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014). +10.27 +Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015). +10.28 +Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015). +10.29 +Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016). +10.30 +Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016). +10.31 +Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017) . +10.32 +Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 9, 2018). +10.33 +Limited Consent and Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of October 1, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 4, 2018). +10.34 +Thirteenth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 1, 2018). +10.35 +Fourteenth Amendment to Third Amended and Restated Credit Agreement, dated as of February 27, 2020, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2019). +10.36 +Fifteenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 23, 2021, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 29, 2021). +10.37 +Fourth Amended and Restated Credit Agreement, dated as of November 18, 2021, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 18, 2021). +10.38† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.39† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.40† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +97 +Table of Contents +10.41† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.42† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.43† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.44† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.45† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.46† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.47† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.48† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.49† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.50† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.51† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.52† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.53† +Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019). +10.54† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.55† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.56† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.57† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.58† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (filed herewith). +10.59† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees without employment agreements (filed herewith). +98 +Table of Contents +10.60† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan with ratable vesting for employees without employment agreements (filed herewith). +10.61† +Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the year ended December 31, 2020). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2021, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +104 Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101). +† Indicates a management contract or compensatory plan or arrangement. +* Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. +99 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +February 28, 2022 By: /s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature Title Date +/s/ Joseph Wm. Foran Chairman and Chief Executive Officer February 28, 2022 +Joseph Wm. Foran (Principal Executive Officer) +/s/ David E. Lancaster Executive Vice President and Chief Financial Officer February 28, 2022 +David E. Lancaster (Principal Financial Officer) +/s/ Robert T. Macalik Senior Vice President and Chief Accounting Officer February 28, 2022 +Robert T. Macalik (Principal Accounting Officer) +/s/ Reynald A. Baribault Director February 28, 2022 +Reynald A. Baribault +/s/ R. Gaines Baty Director February 28, 2022 +R. Gaines Baty +/s/ William M. Byerley Director February 28, 2022 +William M. Byerley +/s/ Monika U. Ehrman Director February 28, 2022 +Monika U. Ehrman +/s/ Julia P. Forrester Rogers Director February 28, 2022 +Julia P. Forrester Rogers +/s/ James M. Howard Director February 28, 2022 +James M. Howard +/s/ Timothy E. Parker Director February 28, 2022 +Timothy E. Parker +/s/ Kenneth L. Stewart Director February 28, 2022 +Kenneth L. Stewart +100 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water. +Bcf . One billion cubic feet of natural gas. +Bench . A geologic zone or formation or a subdivision of a geologic formation. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Central delivery point or CDP . The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differential . The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. +Dry hole . A well found to be incapable of producing hydrocarbons. +ESP . Electric submersible pump. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +101 +Table of Contents +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Lateral length . Length of the drilled or completed portion of a horizontal well. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or produced water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Organization of Petroleum Exporting Countries or OPEC . An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid. +OPEC+ . A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +102 +Table of Contents +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Prospectivity . Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +103 +Table of Contents +Volumetric reserves analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +104 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2021, 2020 and 2019 +Index +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2021 and 2020 +F-4 +Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 +F-5 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019 +F-6 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 +F- 7 +Notes to Consolidated Financial Statements +F- 8 +Unaudited Supplementary Information +F- 37 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation +As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. For the year ended December 31, 2021, the Company recorded depletion expense of evaluated oil and natural gas +F-2 +Table of Contents +properties of $310.1 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company recorded $6.0 billion of gross evaluated oil and natural gas properties as of December 31, 2021. The Company’s internal reserves engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reserves engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company. +We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reserves engineers as well as the external reserves engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reserves engineers, and (3) the relationship of the external reserves engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reserves engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reserves engineers’ estimate regarding future operating and development costs based on historical actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reserves engineers in connection with our evaluation of the Company’s reserves estimates. We analyzed the depletion expense calculation for compliance with industry and regulatory standards, and recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +February 28, 2022 +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2021 2020 +ASSETS +Current assets +Cash $ 48,135 $ 57,916 +Restricted cash 38,785 33,467 +Accounts receivable +Oil and natural gas revenues 164,242 85,098 +Joint interest billings 48,366 34,823 +Other 28,808 17,212 +Derivative instruments 1,971 6,727 +Lease and well equipment inventory 12,188 10,584 +Prepaid expenses and other current assets 28,810 15,802 +Total current assets 371,305 261,629 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated 6,007,325 5,295,931 +Unproved and unevaluated 964,714 902,133 +Midstream properties 900,979 841,695 +Other property and equipment 30,123 29,561 +Less accumulated depletion, depreciation and amortization ( 4,046,456 ) ( 3,701,551 ) +Net property and equipment 3,856,685 3,367,769 +Other assets +Derivative instruments — 2,570 +Other long-term assets 34,163 55,312 +Total assets $ 4,262,153 $ 3,687,280 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable $ 26,256 $ 13,982 +Accrued liabilities 253,283 119,158 +Royalties payable 94,359 66,049 +Amounts due to affiliates 27,324 4,934 +Derivative instruments 16,849 45,186 +Advances from joint interest owners 18,074 4,191 +Other current liabilities 28,692 37,436 +Total current liabilities 464,837 290,936 +Long-term liabilities +Borrowings under Credit Agreement 100,000 440,000 +Borrowings under San Mateo Credit Facility 385,000 334,000 +Senior unsecured notes payable 1,042,580 1,040,998 +Asset retirement obligations 41,689 37,919 +Deferred income taxes 77,938 — +Other long-term liabilities 22,721 30,402 +Total long-term liabilities 1,669,928 1,883,319 +Commitments and contingencies (Note 14) +Shareholders’ equity +Common stock — $ 0.01 par value, 160,000,000 shares authorized; 117,861,923 and 116,847,003 shares issued; and 117,850,233 and 116,844,768 shares outstanding, respectively +1,179 1,169 +Additional paid-in capital 2,077,592 2,027,069 +Accumulated deficit ( 171,318 ) ( 741,705 ) +Treasury stock, at cost, 11,945 and 2,235 shares, respectively +( 243 ) ( 3 ) +Total Matador Resources Company shareholders’ equity 1,907,210 1,286,530 +Non-controlling interest in subsidiaries 220,178 226,495 +Total shareholders’ equity 2,127,388 1,513,025 +Total liabilities and shareholders’ equity $ 4,262,153 $ 3,687,280 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +Year Ended December 31, +2021 2020 2019 +Revenues +Oil and natural gas revenues $ 1,700,542 $ 744,461 $ 892,325 +Third-party midstream services revenues 75,499 64,932 59,110 +Sales of purchased natural gas 86,034 41,742 74,769 +Lease bonus - mineral acreage — 4,062 1,711 +Realized (loss) gain on derivatives ( 220,105 ) 38,937 9,482 +Unrealized gain (loss) on derivatives 21,011 ( 32,008 ) ( 53,727 ) +Total revenues 1,662,981 862,126 983,670 +Expenses +Production taxes, transportation and processing 178,987 93,338 92,273 +Lease operating 108,964 104,953 117,305 +Plant and other midstream services operating 61,459 41,500 36,798 +Purchased natural gas 77,126 32,734 69,398 +Depletion, depreciation and amortization 344,905 361,831 350,540 +Accretion of asset retirement obligations 2,068 1,948 1,822 +Full-cost ceiling impairment — 684,743 — +General and administrative 96,396 62,578 80,054 +Total expenses 869,905 1,383,625 748,190 +Operating income (loss) 793,076 ( 521,499 ) 235,480 +Other income (expense) +Net loss on asset sales and impairment ( 331 ) ( 2,832 ) ( 967 ) +Interest expense ( 74,687 ) ( 76,692 ) ( 73,873 ) +Other (expense) income ( 2,712 ) 1,864 ( 2,126 ) +Total other expense ( 77,730 ) ( 77,660 ) ( 76,966 ) +Income (loss) before income taxes 715,346 ( 599,159 ) 158,514 +Income tax provision (benefit) +Deferred 74,710 ( 45,599 ) 35,532 +Total income tax provision (benefit) 74,710 ( 45,599 ) 35,532 +Net income (loss) 640,636 ( 553,560 ) 122,982 +Net income attributable to non-controlling interest in subsidiaries ( 55,668 ) ( 39,645 ) ( 35,205 ) +Net income (loss) attributable to Matador Resources Company shareholders $ 584,968 $ ( 593,205 ) $ 87,777 +Earnings (loss) per common share +Basic $ 5.00 $ ( 5.11 ) $ 0.75 +Diluted $ 4.91 $ ( 5.11 ) $ 0.75 +Weighted average common shares outstanding +Basic 116,999 116,068 116,555 +Diluted 119,163 116,068 117,063 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2021, 2020 and 2019 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital Accumulated deficit Treasury Stock Non-controlling interest in subsidiaries +Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2019 116,375 $ 1,164 $ 1,924,408 $ ( 236,277 ) 21 $ ( 415 ) $ 1,688,880 $ 90,777 $ 1,779,657 +Issuance of common stock pursuant to employee stock compensation plan 240 2 ( 2 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 50 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 23,396 — — — 23,396 — 23,396 +Stock options exercised, net of options forfeited in net share settlements 220 2 3,298 — — — 3,300 — 3,300 +Liability-based stock option awards settled 1 — 11 — — — 11 — 11 +Restricted stock forfeited — — — — 222 ( 3,691 ) ( 3,691 ) — ( 3,691 ) +Contribution related to formation of San Mateo, net of tax of $ 3.1 million (See Note 6) +— — 11,613 — — — 11,613 — 11,613 +Contribution of property related to formation of San Mateo II (See Note 6) — — ( 506 ) — — — ( 506 ) 506 — +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $ 5.9 million (See Note 6) +— — 22,874 — — — 22,874 48,510 71,384 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 39,200 ) ( 39,200 ) +Cancellation of treasury stock ( 242 ) ( 2 ) ( 4,078 ) — ( 242 ) 4,080 — — — +Current period net income — — — 87,777 — — 87,777 35,205 122,982 +Balance at December 31, 2019 116,644 1,166 1,981,014 ( 148,500 ) 1 ( 26 ) 1,833,654 135,798 1,969,452 +Issuance of common stock pursuant to employee stock compensation plan 244 2 ( 2 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 85 1 ( 1 ) — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 17,452 — — — 17,452 — 17,452 +Stock options exercised, net of options forfeited in net share settlements — — ( 24 ) — — — ( 24 ) — ( 24 ) +Liability-based stock option awards settled in equity 22 — 297 — — — 297 — 297 +Restricted stock forfeited — — — — 149 ( 1,489 ) ( 1,489 ) — ( 1,489 ) +Contribution related to formation of San Mateo, net of tax of $ 3.1 million (See Note 6) +— — 11,613 — — — 11,613 — 11,613 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $ 4.8 million (See Note 6) +— — 18,232 — — — 18,232 96,622 114,854 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 45,570 ) ( 45,570 ) +Cancellation of treasury stock ( 148 ) — ( 1,512 ) — ( 148 ) 1,512 — — — +Current period net (loss) income — — — ( 593,205 ) — — ( 593,205 ) 39,645 ( 553,560 ) +Balance at December 31, 2020 116,847 $ 1,169 $ 2,027,069 $ ( 741,705 ) 2 $ ( 3 ) $ 1,286,530 $ 226,495 $ 1,513,025 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital Accumulated deficit Treasury Stock Non-controlling interest in subsidiaries Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2021 116,847 $ 1,169 $ 2,027,069 $ ( 741,705 ) 2 $ ( 3 ) $ 1,286,530 $ 226,495 $ 1,513,025 +Dividends declared ($ 0.125 per share) +— — — ( 14,581 ) — — ( 14,581 ) — ( 14,581 ) +Issuance of common stock pursuant to employee stock compensation plan 768 7 ( 7 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 81 1 ( 1 ) — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 12,113 — — — 12,113 — 12,113 +Stock options exercised, net of options forfeited in net share settlements 312 3 ( 4,258 ) — — — ( 4,255 ) — ( 4,255 ) +Restricted stock forfeited — — — — 156 ( 2,621 ) ( 2,621 ) — ( 2,621 ) +Contributions related to formation of San Mateo, net of tax of $ 3.6 million (See Note 6) +— — 45,056 — — — 45,056 — 45,056 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 61,985 ) ( 61,985 ) +Cancellation of treasury stock ( 146 ) ( 1 ) ( 2,380 ) — ( 146 ) 2,381 — — — +Current period net income — — — 584,968 — — 584,968 55,668 640,636 +Balance at December 31, 2021 117,862 $ 1,179 $ 2,077,592 $ ( 171,318 ) 12 $ ( 243 ) $ 1,907,210 $ 220,178 $ 2,127,388 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2021 2020 2019 +Operating activities +Net income (loss) $ 640,636 $ ( 553,560 ) $ 122,982 +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized (gain) loss on derivatives ( 21,011 ) 32,008 53,727 +Depletion, depreciation and amortization 344,905 361,831 350,540 +Accretion of asset retirement obligations 2,068 1,948 1,822 +Full-cost ceiling impairment — 684,743 — +Stock-based compensation expense 9,039 13,625 18,505 +Deferred income tax provision (benefit) 74,710 ( 45,599 ) 35,532 +Amortization of debt issuance cost 3,659 2,832 2,484 +Net loss on asset sales and impairment 331 2,832 967 +Changes in operating assets and liabilities +Accounts receivable ( 98,456 ) 53,001 ( 43,261 ) +Lease and well equipment inventory ( 1,537 ) ( 655 ) 4,777 +Prepaid expenses and other current assets ( 11,786 ) ( 3,010 ) ( 4,844 ) +Other long-term assets 56 1,681 678 +Accounts payable, accrued liabilities and other current liabilities 76,891 ( 43,844 ) ( 19,004 ) +Royalties payable 28,310 ( 19,144 ) 20,417 +Advances from joint interest owners 7,018 ( 10,646 ) 3,869 +Other long-term liabilities ( 1,478 ) ( 461 ) 2,851 +Net cash provided by operating activities 1,053,355 477,582 552,042 +Investing activities +Drilling, completion and equipping capital expenditures ( 431,136 ) ( 471,087 ) ( 679,395 ) +Acquisition of oil and natural gas properties ( 238,609 ) ( 72,809 ) ( 50,766 ) +Midstream capital expenditures ( 63,359 ) ( 234,359 ) ( 192,035 ) +Expenditures for other property and equipment ( 376 ) ( 2,200 ) ( 3,701 ) +Proceeds from sale of assets 4,215 4,789 21,921 +Net cash used in investing activities ( 729,265 ) ( 775,666 ) ( 903,976 ) +Financing activities +Repayments of borrowings under Credit Agreement ( 600,000 ) ( 35,000 ) ( 35,000 ) +Borrowings under Credit Agreement 260,000 220,000 250,000 +Repayments of borrowings under San Mateo Credit Facility ( 84,000 ) — — +Borrowings under San Mateo Credit Facility 135,000 46,000 68,000 +Cost to enter into or amend credit facilities ( 4,108 ) ( 660 ) ( 1,443 ) +Proceeds from stock options exercised 1,335 45 3,300 +Dividends paid ( 14,581 ) — — +Contributions related to formation of San Mateo 48,626 14,700 14,700 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries — 119,700 77,330 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries ( 61,985 ) ( 45,570 ) ( 39,200 ) +Taxes paid related to net share settlement of stock-based compensation ( 8,211 ) ( 1,556 ) ( 3,691 ) +Other ( 629 ) 6,680 ( 918 ) +Net cash (used in) provided by financing activities ( 328,553 ) 324,339 333,078 +(Decrease) increase in cash and restricted cash ( 4,463 ) 26,255 ( 18,856 ) +Cash and restricted cash at beginning of period 91,383 65,128 83,984 +Cash and restricted cash at end of period $ 86,920 $ 91,383 $ 65,128 +Supplemental disclosures of cash flow information (Note 15) +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2021, 2020 and 2019 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, San Mateo’s customers or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2021, three significant purchasers accounted for 72 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 29 %), Exxon Mobil Corporation ( 33 %) and BP America Production Company ( 10 %). For the year ended December 31, 2020, two significant purchasers accounted for 65 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 57 %) and Exxon Mobil Corporation ( 8 %). For the year ended December 31, 2019, two significant purchasers accounted for 67 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 53 %) and BP America Production Company ( 14 %). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2021, 2020 and 2019, approximately 39 %, 35 % and 31 %, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $ 38.4 million, $ 30.0 million and $ 31.1 million of its general and administrative costs into oil and natural gas properties in 2021, 2020 and 2019, respectively. The Company capitalized $ 4.8 million, $ 5.0 million and $ 7.6 million of its interest expense into oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019, respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2021, 2020 and 2019, the Company recorded depletion expense of $ 310.1 million, $ 334.8 million and $ 330.7 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10 %, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10 % discount factor is used to determine the present value of future net revenues. For the period from January through December 2021, these average oil and natural gas prices were $ 63.04 per Bbl and $ 3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $ 36.04 per Bbl and $ 1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $ 52.19 per Bbl and $ 2.58 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the years ended December 31, 2021 and 2019, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2021 and 2019. +For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $ 684.7 million, exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related deferred income tax benefit recorded net of a valuation allowance (see Note 8). +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream Properties and Other Property and Equipment +Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. The Company capitalized $ 1.3 million, $ 1.8 million and $ 1.8 million of general and administrative costs into midstream properties in 2021, 2020 and 2019, respectively. The Company did not capitalize any interest expense into midstream properties for the year ended December 31, 2021. The Company capitalized $ 0.5 million and $ 0.9 million of interest expense into midstream properties for the years ended December 31, 2020 and 2019. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment. +The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. +Revenues +The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. +The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2021, 2020 and 2019 (in thousands). +Year Ended December 31, +2021 2020 2019 +Revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 +Lease bonus - mineral acreage — 4,062 1,711 +Realized (loss) gain on derivatives ( 220,105 ) 38,937 9,482 +Unrealized gain (loss) on derivatives 21,011 ( 32,008 ) ( 53,727 ) +Total revenues $ 1,662,981 $ 862,126 $ 983,670 +Year Ended December 31, +2021 2020 2019 +Oil revenues $ 1,205,608 $ 595,507 $ 759,811 +Natural gas revenues 494,934 148,954 132,514 +Third-party midstream services revenues 75,499 64,932 59,110 +Sales of purchased natural gas 86,034 41,742 74,769 +Total revenues from contracts with customers $ 1,862,075 $ 851,135 $ 1,026,204 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). +The Company’s consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019 include a stock-based compensation (non-cash) expense of $ 9.0 million, $ 13.6 million and $ 18.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $ 0.9 million, $ 1.0 million and $ 1.4 million for the years ended December 31, 2021, 2020 and 2019, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of operations for the years ended December 31, 2021, 2020 and 2019 also includes $ 20.4 million, $ 4.0 million and $ 3.2 million, respectively, related to liability-based awards expected to be settled in cash. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2021, 2020 and 2019, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2021, 2020 and 2019. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2021, 2020 and 2019 (in thousands, except per share data). +Year Ended December 31, +2021 2020 2019 +Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 584,968 $ ( 593,205 ) $ 87,777 +Weighted average common shares outstanding — denominator +Basic 116,999 116,068 116,555 +Dilutive effect of options and restricted stock units 2,164 — 508 +Diluted weighted average common shares outstanding 119,163 116,068 117,063 +Earnings (loss) per common share attributable to Matador Resources Company shareholders +Basic $ 5.00 $ ( 5.11 ) $ 0.75 +Diluted $ 4.91 $ ( 5.11 ) $ 0.75 +A total of 2.5 million and 2.6 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2020 and 2019, respectively, because their effects were anti-dilutive. Additionally, 0.7 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2021 were with The Bank of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates thereof), and all but BMO Harris Financing, Inc. (Bank of Montreal) were parties that are lenders (or affiliates thereof) under the Company’s reserves-based revolving credit agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2021 and 2020 (in thousands). +December 31, +2021 2020 +Oil and natural gas properties +Evaluated (subject to amortization) $ 6,007,325 $ 5,295,931 +Unproved and unevaluated (not subject to amortization) 964,714 902,133 +Total oil and natural gas properties 6,972,039 6,198,064 +Accumulated depletion ( 3,933,355 ) ( 3,623,265 ) +Net oil and natural gas properties 3,038,684 2,574,799 +Midstream properties +Midstream equipment and facilities 900,979 841,695 +Accumulated depreciation ( 92,574 ) ( 61,113 ) +Net midstream properties 808,405 780,582 +Other property and equipment +Furniture, fixtures and other equipment 10,923 10,591 +Software 8,225 8,116 +Leasehold improvements 10,975 10,854 +Total other property and equipment 30,123 29,561 +Accumulated depreciation ( 20,527 ) ( 17,173 ) +Net other property and equipment 9,596 12,388 +Net property and equipment $ 3,856,685 $ 3,367,769 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2021 and the year in which these costs were incurred (in thousands). +Description 2021 2020 2019 2018 2017 and prior Total +Costs incurred for +Property acquisition $ 111,120 $ 40,355 $ 40,140 $ 417,114 $ 287,666 $ 896,395 +Exploration wells 14,738 411 1,199 123 274 16,745 +Development wells 46,232 2,027 3,245 60 10 51,574 +Total $ 172,090 $ 42,793 $ 44,584 $ 417,297 $ 287,950 $ 964,714 +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2021 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $ 68.3 million at December 31, 2021. Of this total, $ 16.7 million was associated with exploration wells and $ 51.6 million was associated with development wells. The +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Company anticipates that most of the $ 68.3 million associated with these wells in progress at December 31, 2021 will be transferred to the amortization base during 2022. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2021 are costs related to the advanced preparation for wells that the Company intends to drill in the future. +NOTE 4 — LEASES +The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2021 were 2.73 % and 1.99 % for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2021 and 2020, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. +Year Ended December 31, +2021 2020 +Operating leases +Lease operating $ 11,393 $ 12,994 +Plant and other midstream services 36 28 +General and administrative 3,645 3,698 +Total operating leases (1) +15,074 16,720 +Short-term leases +Lease operating 11,234 12,890 +Plant and other midstream services 4,037 5,689 +General and administrative 37 47 +Total short-term leases (2)(3) +15,308 18,626 +Financing leases +Depreciation of assets 566 747 +Interest on lease liabilities 138 123 +Total financing leases 704 870 +Total lease expense $ 31,086 $ 36,216 +_____________________ +(1) Does not include gross payments related to drilling rig leases of $ 31.9 million and $ 33.6 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. +(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. +(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $ 61.7 million and $ 65.3 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively. +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2021 and 2020, respectively (in thousands). +December 31, +2021 2020 +Operating leases +Other long-term assets $ 29,519 $ 51,528 +Other current liabilities $ ( 19,649 ) $ ( 35,716 ) +Other long-term liabilities ( 15,340 ) ( 21,598 ) +Total operating lease liabilities $ ( 34,989 ) $ ( 57,314 ) +Financing leases +Other property and equipment, at cost $ 5,914 $ 3,673 +Accumulated depreciation ( 3,485 ) ( 2,134 ) +Net property and equipment $ 2,429 $ 1,539 +Other current liabilities $ ( 378 ) $ ( 621 ) +Other long-term liabilities ( 45 ) ( 256 ) +Total financing lease liabilities $ ( 423 ) $ ( 877 ) +The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2021 and 2020, respectively (in thousands). +Year Ended December 31, +2021 2020 +Cash paid related to lease liabilities +Operating cash payments for operating leases $ 14,430 $ 15,664 +Investing cash payments for operating leases $ 31,967 $ 33,556 +Financing cash payments for financing leases $ 629 $ 790 +Right of use assets obtained in exchange for lease obligations entered into during the period +Operating leases $ 18,454 $ 12,474 +Financing leases $ 2,241 $ 996 +The following table presents the maturities of lease liabilities at December 31, 2021 (in years). +Weighted-Average Remaining Lease Term December 31, 2021 +Operating leases 2.5 +Financing leases 1.7 +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 4 — LEASES — Continued +The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2021 (in thousands). +December 31, 2021 +Operating Leases Financing Leases +2022 $ 19,649 $ 378 +2023 6,830 180 +2024 4,217 37 +2025 4,287 — +2026 1,553 — +Thereafter — — +Total lease payments 36,536 595 +Less imputed interest ( 1,547 ) ( 172 ) +Total lease obligations 34,989 423 +Less current obligations ( 19,649 ) ( 378 ) +Long-term lease obligations $ 15,340 $ 45 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS +The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2021 and 2020 (in thousands). +Year Ended December 31, +2021 2020 +Beginning asset retirement obligations $ 38,542 $ 36,211 +Liabilities incurred during period 2,294 2,548 +Liabilities settled during period ( 151 ) ( 290 ) +Revisions in estimated cash flows 86 ( 1,875 ) +Divestitures during the period ( 880 ) — +Accretion expense 2,068 1,948 +Ending asset retirement obligations 41,959 38,542 +Less: current asset retirement obligations (1) +( 270 ) ( 623 ) +Long-term asset retirement obligations $ 41,689 $ 37,919 +__________________ +(1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2021 and 2020. +F-18 +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES +Business Combination +On December 14, 2021, the Company completed an acquisition of assets from a private operator. This acquisition was accounted for as a business combination in accordance with ASC Topic 805, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. The Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, strategically located primarily within the Company’s existing acreage in its Ranger and Arrowhead asset areas. +As consideration for the business combination, the Company paid approximately $ 161.7 million in cash and will pay an additional $ 6.5 million, net of customary working capital adjustments, including adjusting for production, revenues, operating expenses and capital expenditures from August 1, 2021 to closing. In addition, the Company will increase the purchase price by $ 5.0 million for each quarter during 2022 in which the average oil price, as defined in the purchase and sale agreement, is greater than $ 75.00 per barrel. The Company recorded this contingent consideration at fair value on the date of the business combination and will record the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of operations. The fair value of the contingent consideration increased between December 14, 2021 and December 31, 2021 by $ 1.5 million, which was recorded as “Other expense” for the year ended December 31, 2021. The Company used the Monte Carlo simulation method to measure the fair value of the contingent consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy). +In addition, the Company acquired oil and natural gas production of approximately 3,500 BOE per day at the date of acquisition, which increased the Company’s revenues and net income for the period from December 15, 2021 through December 31, 2021 by $ 4.0 million and $ 3.2 million, respectively. The pro forma impact of this business combination to revenues and net income for the remainder of 2021 would not be material to the Company’s 2021 revenues and net income as reported. +The preliminary allocation of the consideration given related to this business combination was as follows (in thousands). The Company anticipates that the allocation of the consideration given should be finalized during 2022 upon determination of the final customary purchase price adjustments. +Consideration given +Allocation +Cash +$ 161,680 +Working capital adjustments to be paid in 2022 6,500 +Fair value of contingent consideration at December 14, 2021 +6,718 +Total consideration given +$ 174,898 +Allocation of purchase price +Oil and natural gas properties +Evaluated +$ 139,312 +Unproved and unevaluated +43,204 +Accrued liabilities +( 360 ) +Advances from joint interest owners ( 6,865 ) +Asset retirement obligations +( 393 ) +Net assets acquired +$ 174,898 +Joint Ventures +At December 31, 2021, the Company owned 51 % of San Mateo, a midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) in portions of Eddy County, New Mexico and Loving County, Texas. At December 31, 2021, Five Point owned the remaining 49 % of San Mateo. The midstream assets include (i) the Black River Processing Plant, (ii) 14 salt water disposal wells and associated commercial salt water disposal facilities and (iii) approximately 370 miles of oil gathering and transportation pipelines, natural gas gathering pipelines and produced water pipelines. The Company operates San Mateo, and San Mateo is consolidated in the Company’s financial statements, with Five Point’s interest being accounted for as a non-controlling interest. +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +As part of the joint venture agreement with Five Point, the Company had the potential to earn two different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $ 73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and its Wolf asset area in Loving County over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. At December 31, 2021, the Company had earned $ 58.8 million of the potential $ 73.5 million in performance incentives and Five Point had paid $ 14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021. The Company may earn up to the remaining $ 14.7 million in performance incentives until January 31, 2023. Beginning in 2019, the Company had the potential to earn up to $ 150.0 million in additional deferred performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area over the next several years, plus additional performance incentives for securing volumes from third-party customers. During the year ended December 31, 2021, Five Point paid $ 33.9 million in these additional performance incentives. +The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15 -year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee natural gas processing agreements (see Note 14). +During the years ended December 31, 2021 and 2020, San Mateo distributed $ 64.5 million and $ 47.4 million, respectively, to the Company and $ 62.0 million and $ 45.6 million, respectively, to Five Point. During the year ended December 31, 2021, neither the Company nor Five Point contributed cash to San Mateo. During the year ended December 31, 2020, the Company contributed $ 75.0 million and Five Point contributed $ 119.7 million of cash to San Mateo, of which $ 23.1 million was paid to carry Matador’s proportionate interest in San Mateo Midstream II, LLC (“San Mateo II”). Five Point agreed to carry a portion of Matador’s proportionate interest as part of the formation agreement for San Mateo II. The amount that Five Point paid to carry Matador’s proportionate interest in San Mateo was recorded in “Additional paid-in capital” in the Company’s consolidated balance sheets at December 31, 2020, net of the $ 4.8 million deferred tax impact to Matador related to this equity contribution. During the year ended December 31, 2019, the Company contributed $ 24.2 million and Five Point contributed $ 77.3 million of cash to San Mateo, of which $ 28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $ 5.9 million deferred tax impact to Matador related to this equity contribution. In the first quarter of 2019, the Company also contributed $ 1.0 million of property to San Mateo II. San Mateo II was merged with and into San Mateo effective October 1, 2020. +Divestitures +During 2021 and 2020, the Company converted approximately $ 4.2 million and $ 4.8 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana. +NOTE 7 — DEBT +At December 31, 2021, the Company had (i) $ 1.05 billion of outstanding senior notes due 2026, (ii) $ 100.0 million in borrowings outstanding under its reserves-based revolving credit facility, (iii) approximately $ 45.8 million in outstanding letters of credit issued pursuant to its revolving credit facility and (iv) $ 7.5 million outstanding under an unsecured U.S. Small Business Administration loan. +At December 31, 2021, San Mateo had $ 385.0 million in borrowings outstanding under its revolving credit facility and approximately $ 9.0 million in outstanding letters of credit issued pursuant to its revolving credit facility. +Credit Agreements +MRC Energy Company +On November 18, 2021, the Company entered into its Fourth Amended and Restated credit facility with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85 % of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. In addition, all obligations under the +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 7 — DEBT — Continued +Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The Credit Agreement matures on October 31, 2026 or, if earlier, the date that is 180 days prior to the earliest stated redemption date of any senior notes of the Company with an outstanding principal balance in excess of $ 25.0 million. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. +In November 2021, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $ 900.0 million to $ 1.35 billion. The Company elected to keep the borrowing commitment at $ 700.0 million, and the maximum facility amount remained $ 1.5 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). +In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +Total deferred loan costs were $ 3.9 million at December 31, 2021, and these costs are being amortized over the term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 1.85 % at December 31, 2021. At December 31, 2021, the Company had $ 100.0 million in borrowings outstanding under the Credit Agreement and approximately $ 45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. Between December 31, 2021 and February 28, 2022, the Company repaid $ 25.0 million of borrowings outstanding under the Credit Agreement. +Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If MRC borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50 %, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0 % plus, in each case, an amount ranging from 0.75 % to 1.75 % per annum depending on the level of borrowings under the Credit Agreement. If MRC borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.75 % to 2.75 % per annum depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, three or six months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375 % to 0.50 % per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $ 75 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of its assets; +• enter into commodity hedging agreements or interest rate agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 7 — DEBT — Continued +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and +• take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and +• a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2021. +San Mateo Midstream, LLC +On December 19, 2018, San Mateo entered into a $ 250.0 million credit facility with the lenders party thereto, currently led by Truist Bank as administrative agent (the “San Mateo Credit Facility”). The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under the revolving credit facility from $ 375.0 million to $ 450.0 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50 %. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $ 700.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. +Total deferred loan costs were $ 1.9 million at December 31, 2021, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 2.11 % at December 31, 2021. At December 31, 2021, San Mateo had $ 385.0 million in borrowings outstanding under the San Mateo Credit Facility and $ 9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between December 31, 2021 and February 22, 2022, San Mateo repaid $ 30.0 million of borrowings outstanding under the San Mateo Credit Facility. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50 %, and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0 % plus, in each case, an amount ranging from 1.00 % to 2.00 % per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 2.00 % to 3.00 % per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +A commitment fee of 0.30 % to 0.50 % per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. The San Mateo Credit Facility also restricts the ability +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 7 — DEBT — Continued +of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of San Mateo’s assets; +• enter into hedging agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and +• issue equity interests in San Mateo or its subsidiaries. +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving San Mateo or its subsidiaries; and +• a change of control, as defined in the San Mateo Credit Facility. +The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2021. +Senior Unsecured Notes +At December 31, 2021, the Company had $ 1.05 billion of outstanding 5.875 % senior notes due 2026 that were registered under the Securities Act and mature September 15, 2026 (the “Notes”). Interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries (as defined in the Indenture) or Guarantors of the Notes. +The Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: +Year Redemption Price +2021 104.406 % +2022 102.938 % +2023 101.469 % +2024 and thereafter 100.000 % +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 7 — DEBT — Continued +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• default for 30 days in the payment when due of interest on the Notes; +• default in the payment when due of the principal of, or premium, if any, on the Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 50.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 50.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +The outstanding borrowings of $ 100.0 million at December 31, 2021 under the Credit Agreement mature on October 31, 2026. The outstanding borrowings of $ 385.0 million at December 31, 2021 under the San Mateo Credit Facility mature on December 19, 2023. The $ 1.05 billion of outstanding Notes at December 31, 2021 mature on September 15, 2026. +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2020, 2019 and 2018 +NOTE 8 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2021 and 2020 is as follows (in thousands). +December 31, +2021 2020 +Deferred tax assets +Net operating loss carryforwards $ 129,651 $ 122,952 +Unrealized loss on derivatives 3,729 8,997 +Percentage depletion carryover 1,770 1,462 +Compensation 9,838 10,405 +Lease liabilities 4,866 9,380 +Other 9,410 8,334 +Total deferred tax assets 159,264 161,530 +Valuation allowance on deferred tax assets ( 10,599 ) ( 110,681 ) +Total deferred tax assets, net of valuation allowance 148,665 50,849 +Deferred tax liabilities +Property and equipment ( 179,153 ) ( 11,879 ) +Less than wholly-owned subsidiaries ( 39,900 ) ( 26,564 ) +Lease right of use assets ( 4,866 ) ( 9,380 ) +Other ( 2,684 ) ( 2,684 ) +Total deferred tax liabilities ( 226,603 ) ( 50,507 ) +Net deferred tax (liabilities) assets $ ( 77,938 ) $ 342 +At December 31, 2021, the Company had net operating loss carryforwards of $ 555.2 million for federal income tax purposes and $ 223.3 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027. +At December 31, 2020, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. The remaining net deferred tax asset at December 31, 2020 relates to state taxes, for which the deferred taxes were determined to be more likely than not to be utilized. Due to a variety of factors, including the Company’s significant net income in 2021, the Company’s federal valuation allowance was reversed as of September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. +The current income tax provision and the deferred income tax provision for the years ended December 31, 2021, 2020 and 2019 were comprised of the following (in thousands). +Year Ended December 31, +2021 2020 2019 +Deferred income tax provision (benefit) +Federal income tax $ 44,883 $ ( 25,675 ) $ 29,171 +State income tax 29,827 ( 19,924 ) 6,361 +Net deferred income tax provision (benefit) $ 74,710 $ ( 45,599 ) $ 35,532 +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 8 — INCOME TAXES — Continued +Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2021, 2020 and 2019 is as follows (in thousands). +Year Ended December 31, +2021 2020 2019 +Federal tax expense (benefit) at statutory rate (1) +$ 150,223 $ ( 125,823 ) $ 33,441 +State income tax 26,646 ( 20,607 ) 6,141 +Permanent differences ( 2,078 ) ( 3,114 ) ( 4,267 ) +Change in federal valuation allowance ( 103,262 ) 103,262 — +Change in state valuation allowance 3,181 683 217 +Net deferred income tax provision (benefit) 74,710 ( 45,599 ) 35,532 +Total income tax provision (benefit) $ 74,710 $ ( 45,599 ) $ 35,532 +__________________ +(1) The statutory federal tax rate was 21% for the years ended December 31, 2021, 2020 and 2019. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2018. The earliest tax year open for examination for the State of Texas tax return is 2017. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2021, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +NOTE 9 — STOCK-BASED COMPENSATION +Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards +In 2012, the Company’s Board of Directors adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. +In 2019, the Company’s Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of December 31, 2021, the 2019 Incentive Plan provided for a maximum of 1,571,972 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled. +The 2012 Incentive Plan and the 2019 Incentive Plan are administered by the independent members of the Board of Directors, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. +During the years ended December 31, 2021, 2020 and 2019, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. +Stock Options +Under the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted and are outstanding to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or 10 years. The 2012 Incentive Plan defines fair market value as the closing price of Matador’s common stock on the date of grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing price of Matador’s common stock on the trading day prior to the date of grant. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +The weighted average grant date fair value for stock option awards granted under the 2019 Incentive Plan was estimated using the following weighted average assumptions during the year ended December 31, 2019. The Company did not grant stock option awards during the years ended December 31, 2021 and 2020. +2019 +Stock option pricing model Black Scholes Merton +Expected option life 4.00 years +Risk-free interest rate 1.46 % +Volatility 48.52 % +Dividend yield — % +Estimated forfeiture rate 4.43 % +Weighted average fair value of stock option awards granted during the year $ 5.04 +The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate was the rate for constant yield U.S. Treasury securities with a term to maturity that was consistent with the expected term of the award. +Summarized information about stock options outstanding at December 31, 2021 under the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2020 2,473 $ 23.08 +Options granted — $ — +Options exercised ( 1,368 ) $ 25.37 +Options forfeited ( 37 ) $ 18.72 +Options expired ( 465 ) $ 16.90 +Options outstanding at December 31, 2021 603 $ 22.92 +Options outstanding at +December 31, 2021 Options exercisable at +December 31, 2021 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$ 14.48 - $ 15.40 +240 3.66 $ 14.80 82 $ 14.80 +$ 26.86 - $ 29.68 +363 1.59 $ 28.28 363 $ 28.28 +At December 31, 2021, the aggregate intrinsic value for both outstanding and exercisable options was $ 4.9 million, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2021 was 1.97 years. +The total intrinsic value of options exercised during the years ended December 31, 2021, 2020 and 2019 was $ 15.8 million, $ 0.3 million and $ 0.8 million, respectively. The tax related benefit realized from the exercise of stock options totaled $ 16.8 million, $ 1.4 million and $ 2.8 million for the years ended December 31, 2021, 2020 and 2019, respectively. +At December 31, 2021, the total remaining unrecognized compensation expense related to unvested stock options was approximately $ 0.5 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 0.66 years. +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +The fair value of options vested during 2021, 2020 and 2019 was $ 3.0 million, $ 6.7 million and $ 9.7 million, respectively. +Service-Based Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2021, 2020 and 2019 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year period. Performance-based restricted stock units granted in 2021 and 2020 vest in an amount between zero and 200 % of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2023 and 2022, respectively, as compared to a designated peer group, and will be settled in equity. +Equity-Based +A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2021 is presented below (in thousands, except fair value). +Restricted Stock Restricted Stock Units +Service Based Service Based Performance Based +Non-vested restricted stock and +restricted stock units Shares Weighted +average +fair +value Shares Weighted +average +fair +value Shares Weighted +average +fair +value +Non-vested at December 31, 2020 682 $ 20.01 75 $ 8.85 1,069 $ 9.05 +Granted 283 $ 37.56 36 $ 30.97 366 $ 50.53 +Vested (1) +( 334 ) $ 27.14 ( 78 ) $ 9.02 ( 397 ) $ 20.00 +Forfeited ( 42 ) $ 17.35 — $ — ( 75 ) $ 9.33 +Non-vested at December 31, 2021 589 $ 24.59 33 $ 33.39 963 $ 20.26 +__________________ +(1) On December 31, 2021, 396,827 of the performance-based awards that were granted in 2019 vested. The vested units earned 200 % for each vested award representing 793,654 aggregate shares of common stock, which were issued on December 31, 2021. +Liability-Based +A summary of the non-vested liability-based restricted stock units as of December 31, 2021 is presented below (in thousands). +Non-vested +restricted stock units Shares +Non-vested at December 31, 2020 1,319 +Granted 357 +Vested ( 487 ) +Forfeited ( 87 ) +Non-vested at December 31, 2021 1,102 +The Company settled 487,252 liability-based awards for $ 12.4 million and 226,363 liability-based awards for $ 2.4 million in cash for the years ended December 31, 2021 and 2020, respectively. The Company did not settle any liability awards for the year ended December 31, 2019. +At December 31, 2021, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ 99.2 million, of which $ 40.7 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +At December 31, 2021, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $ 50.3 million, of which $ 24.0 million is expected to be settled in cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 2.0 years. +The fair value of restricted stock and restricted stock units vested during 2021, 2020 and 2019 was $ 51.9 million, $ 8.4 million and $ 13.6 million, respectively. +Summary +During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to stock options was $ 1.0 million, $ 3.4 million and $ 6.4 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to restricted stock and restricted stock units was $ 36.3 million, $ 17.7 million and $ 20.2 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the Company capitalized $ 7.2 million, $ 3.6 million and $ 5.0 million, respectively, related to stock-based compensation and expensed the remaining $ 30.0 million, $ 17.6 million and $ 21.6 million, respectively. +The total tax benefit recognized for all stock-based compensation was $ 7.9 million, $ 4.5 million and $ 5.6 million for the years ended December 31, 2021, 2020 and 2019, respectively. +NOTE 10 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3 % of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $ 1.6 million, $ 1.4 million and $ 1.4 million in 2021, 2020 and 2019, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $ 2.1 million, $ 1.8 million and $ 1.7 million in 2021, 2020 and 2019, respectively. The Company made no additional contributions in any reporting period presented. +NOTE 11 — EQUITY +Common Stock Dividend +The Company’s Board of Directors (the “Board”) declared a quarterly cash dividend of $ 0.025 per share of common stock in each of the first three quarters of 2021 and, in October 2021, the Board amended the Company’s dividend policy to increase the quarterly dividend and declared a quarterly cash dividend of $ 0.05 per share of common stock. Total cash dividends declared and paid totaled $ 14.6 million during the year ended December 31, 2021. There were no cash dividends declared or paid prior to 2021. +Treasury Stock +On October 21, 2021, October 22, 2020 and October 24, 2019, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2021, 2020 and 2019, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2021, 2020 and 2019 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2021, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. At December 31, 2021, each contract was set to expire at varying times during 2022. The Company had no open contracts associated with NGL prices at December 31, 2021. +The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2021. +Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or +$/MMBtu) Weighted Average Price Ceiling ($/Bbl or +$/MMBtu) Fair Value of Asset (Liability) (thousands) +Commodity Calculation Period +Oil 01/01/2022 - 12/31/2022 2,040,000 $ 50.00 $ 67.85 $ ( 16,652 ) +Natural Gas 01/01/2022 - 03/31/2022 8,250,000 $ 2.70 $ 6.33 ( 151 ) +Total open costless collar contracts $ ( 16,803 ) +The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2021. +Commodity Calculation Period Notional Quantity (Bbl) Fixed Price +($/Bbl) Fair Value of Asset (Liability) (thousands) +Oil Basis 01/01/2022 - 12/31/2022 5,520,000 $ 0.95 1,925 +Total open basis swap contracts $ 1,925 +At December 31, 2021, the Company had an aggregate net liability value for open derivative financial instruments of $ 14.9 million. +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2021 and December 31, 2020 (in thousands). +Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets +December 31, 2021 +Current assets $ 215,145 $ ( 213,174 ) $ 1,971 +Current liabilities ( 230,023 ) 213,174 ( 16,849 ) +Total $ ( 14,878 ) $ — $ ( 14,878 ) +December 31, 2020 +Current assets $ 382,328 $ ( 375,601 ) $ 6,727 +Other assets 150,194 ( 147,624 ) 2,570 +Current liabilities ( 420,787 ) 375,601 ( 45,186 ) +Long-term liabilities ( 147,624 ) 147,624 — +Total $ ( 35,889 ) $ — $ ( 35,889 ) +The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). +Year Ended December 31, +Type of Instrument Location in Statements of Operations 2021 2020 2019 +Derivative Instrument +Oil Revenues: Realized (loss) gain on derivatives $ ( 194,058 ) $ 38,937 $ 9,026 +Natural Gas Revenues: Realized (loss) gain on derivatives ( 26,047 ) — 456 +Realized (loss) gain on derivatives ( 220,105 ) 38,937 9,482 +Oil Revenues: Unrealized gain (loss) on derivatives 26,857 ( 37,703 ) ( 53,443 ) +Natural Gas Revenues: Unrealized (loss) gain on derivatives ( 5,846 ) 5,695 ( 284 ) +Unrealized gain (loss) on derivatives 21,011 ( 32,008 ) ( 53,727 ) +Total $ ( 199,094 ) $ 6,929 $ ( 44,245 ) +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 13 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2021 and 2020 (in thousands). +Fair Value Measurements at +December 31, 2021 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Oil derivatives and basis swaps $ — $ ( 14,727 ) $ — $ ( 14,727 ) +Natural gas derivatives — ( 151 ) — ( 151 ) +Contingent consideration related to business combination — — ( 8,203 ) ( 8,203 ) +Total $ — $ ( 14,878 ) $ ( 8,203 ) $ ( 23,081 ) +Fair Value Measurements at +December 31, 2020 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Oil derivatives and basis swaps $ — $ ( 41,584 ) $ — $ ( 41,584 ) +Natural gas derivatives — 5,695 — 5,695 +Total $ — $ ( 35,889 ) $ — $ ( 35,889 ) +Additional disclosures related to derivative financial instruments are provided in Note 12. +Other Fair Value Measurements +At December 31, 2021 and 2020, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities. +At December 31, 2021 and 2020, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2021 and 2020, the fair value of the Notes was $ 1.08 billion and $ 1.03 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 13 — FAIR VALUE MEASUREMENTS — Continued +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2021 and 2020. +NOTE 14 — COMMITMENTS AND CONTINGENCIES +Processing, Transportation and Produced Water Disposal Commitments +Firm Commitments +From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $ 48.7 million and $ 46.0 million for deliveries under these agreements during the years ended December 31, 2021 and 2020, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2021, the total deficiencies required to be paid by the Company under these agreements would be approximately $ 597.3 million. +San Mateo Commitments +The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15 -year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2021 was approximately $ 390.3 million. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $ 10.8 million at December 31, 2021. +At December 31, 2021, the Company had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these operated and non-operated wells were approximately $ 65.4 million at December 31, 2021. The Company expects these costs to be incurred within the next three years. +Legal Proceedings +The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 15 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2021 and 2020 (in thousands). +December 31, +2021 2020 +Accrued evaluated and unproved and unevaluated property costs $ 128,598 $ 44,012 +Accrued midstream properties costs 7,799 12,776 +Accrued lease operating expenses 32,182 24,276 +Accrued interest on debt 18,232 18,315 +Accrued asset retirement obligations 270 623 +Accrued partners’ share of joint interest charges 17,460 7,407 +Accrued payable related to purchased natural gas 11,284 418 +Other 37,458 11,331 +Total accrued liabilities $ 253,283 $ 119,158 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2021, 2020 and 2019 (in thousands). +Year Ended December 31, +2021 2020 2019 +Cash paid for interest expense, net of amounts capitalized $ 74,843 $ 76,880 $ 75,525 +Increase (decrease) in asset retirement obligations related to mineral properties $ 1,091 $ ( 208 ) $ 2,912 +Increase in asset retirement obligations related to midstream properties $ 257 $ 690 $ 1,204 +Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures $ 80,255 $ ( 26,126 ) $ ( 13,310 ) +Increase (decrease) increase in liabilities for acquisition of oil and natural gas properties $ 2,981 $ ( 2,346 ) $ ( 2,567 ) +(Decrease) increase in liabilities for midstream capital expenditures $ ( 4,478 ) $ ( 33,609 ) $ 30,374 +Stock-based compensation expense recognized as liability $ 24,494 $ 3,702 $ 3,170 +Transfer of inventory (to) from oil and natural gas properties $ ( 398 ) $ 608 $ 1,515 +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2021 2020 2019 +Cash $ 48,135 $ 57,916 $ 40,024 +Restricted cash 38,785 33,467 25,104 +Total cash and restricted cash $ 86,920 $ 91,383 $ 65,128 +NOTE 16 - SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 16 — SEGMENT INFORMATION — Continued +Stateline asset areas and the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations, are conducted through San Mateo (see Note 6). San Mateo and its subsidiaries are not guarantors of the Notes or the Credit Agreement. +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2021 +Oil and natural gas revenues $ 1,695,032 $ 5,510 $ — $ — $ 1,700,542 +Midstream services revenues — 228,817 — ( 153,318 ) 75,499 +Sales of purchased natural gas 47,398 38,636 — — 86,034 +Realized loss on derivatives ( 220,105 ) — — — ( 220,105 ) +Unrealized gain on derivatives 21,011 — — — 21,011 +Expenses (1) +794,880 142,444 85,899 ( 153,318 ) 869,905 +Operating income (2) +$ 748,456 $ 130,519 $ ( 85,899 ) $ — $ 793,076 +Total assets (3) +$ 3,324,681 $ 879,672 $ 57,800 $ — $ 4,262,153 +Capital expenditures (4) +$ 778,191 $ 59,361 $ 376 $ — $ 837,928 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 310.9 million and $ 31.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.6 million. +(2) Includes $ 55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2020 +Oil and natural gas revenues $ 741,092 $ 3,369 $ — $ — $ 744,461 +Midstream services revenues — 166,194 — ( 101,262 ) 64,932 +Sales of purchased natural gas 20,736 21,006 — — 41,742 +Lease bonus - mineral acreage 4,062 — — — 4,062 +Realized gain on derivatives 38,937 — — — 38,937 +Unrealized loss on derivatives ( 32,008 ) — — — ( 32,008 ) +Expenses (1) +1,334,378 97,599 52,910 ( 101,262 ) 1,383,625 +Operating (loss) income (2) +$ ( 561,559 ) $ 92,970 $ ( 52,910 ) $ — $ ( 521,499 ) +Total assets (3) +$ 2,782,819 $ 836,509 $ 67,952 $ — $ 3,687,280 +Capital expenditures (4) +$ 518,198 $ 201,440 $ 2,200 $ — $ 721,838 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 335.8 million and $ 23.3 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $ 684.7 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $ 2.7 million. +(2) Includes $ 39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2019 +Oil and natural gas revenues $ 886,127 $ 6,198 $ — $ — $ 892,325 +Midstream services revenues — 135,953 — ( 76,843 ) 59,110 +Sales of purchased natural gas 4,802 69,967 — — 74,769 +Lease bonus - mineral acreage 1,711 — — — 1,711 +Realized gain on derivatives 9,482 — — — 9,482 +Unrealized loss on derivatives ( 53,727 ) — — — ( 53,727 ) +Expenses (1) +621,687 130,612 72,734 ( 76,843 ) 748,190 +Operating income (loss) (2) +$ 226,708 $ 81,506 $ ( 72,734 ) $ — $ 235,480 +Total assets (3) +$ 3,360,725 $ 647,937 $ 61,014 $ — $ 4,069,676 +Capital expenditures (4) +$ 718,712 $ 223,612 $ 3,701 $ — $ 946,025 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 331.7 million and $ 16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.7 million. +(2) Includes $ 35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2021, 2020 and 2019 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019 (in thousands). +Year Ended December 31, +2021 2020 2019 +Property acquisition costs +Proved $ 145,759 $ 8,003 $ 3,767 +Unproved and unevaluated 104,582 61,984 39,595 +Exploration costs 51,534 29,370 109,439 +Development costs 476,316 418,840 570,290 +Total costs incurred (1) +$ 778,191 $ 518,197 $ 723,091 +__________________ +(1) Excludes midstream-related development and corporate costs of approximately $59.7 million, $203.6 million and $227.3 million for the years ended December 31, 2021, 2020 and 2019, respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the year ended December 31, 2021, approximately 58% of the Company’s property acquisition costs resulted from the acquisition of proved properties, while for the years ended December 31, 2020 and 2019, most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the years ended December 31, 2021, 2020 and 2019, the Company capitalized $7.5 million, zero and $2.9 million, respectively, of geological and geophysical costs, which are included as exploration costs in the table above. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were an increase of $1.4 million, a reduction of $0.2 million and an increase of $4.3 million for the years ended December 31, 2021, 2020 and 2019, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $38.4 million, $30.0 million and $31.1 million of these internal costs for the years ended December 31, 2021, 2020 and 2019, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $4.8 million, $5.0 million and $7.6 million of its interest expense for the years ended December 31, 2021, 2020 and 2019, respectively, excluding midstream-related capitalized interest expense. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2021, 2020 and 2019 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2021, 2020 and 2019 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2021, 2020 and 2019 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +Net Proved Reserves +Oil Natural Gas Oil +Equivalent +(MBbl) (MMcf) (MBOE) +Total at December 31, 2018 123,401 551,474 215,313 +Revisions of prior estimates (605) 34,062 5,073 +Net divestitures of minerals-in-place (298) (12,048) (2,307) +Extensions and discoveries 39,477 114,833 58,616 +Production (13,984) (61,083) (24,164) +Total at December 31, 2019 147,991 627,238 252,531 +Revisions of prior estimates 6,587 19,444 9,828 +Net acquisitions of minerals-in-place 11 1,078 190 +Extensions and discoveries 21,291 84,043 35,297 +Production (15,931) (69,501) (27,514) +Total at December 31, 2020 159,949 662,302 270,332 +Revisions of prior estimates 14,346 165,423 41,916 +Net acquisitions of minerals-in-place 7,533 11,976 9,529 +Extensions and discoveries 17,318 94,532 33,074 +Production (17,840) (81,686) (31,454) +Total at December 31, 2021 181,306 852,547 323,397 +Proved Developed Reserves +December 31, 2018 53,223 246,229 94,261 +December 31, 2019 59,667 276,258 105,710 +December 31, 2020 69,647 323,160 123,507 +December 31, 2021 102,233 546,173 193,262 +Proved Undeveloped Reserves +December 31, 2018 70,178 305,245 121,052 +December 31, 2019 88,324 350,980 146,821 +December 31, 2020 90,301 339,142 146,825 +December 31, 2021 79,073 306,374 130,135 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2021, 2020 and 2019. +The Company’s proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. The Company’s proved oil and natural gas reserves increased by 84.5 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021, resulting in a net increase of 53.1 million BOE. The Company added 33.1 million BOE in proved reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of our properties in the Delaware Basin. As the Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 16.3 million BOE to proved +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2021, 2020 and 2019 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +reserves at a future date. The Company also realized 41.9 million BOE in net upward revisions to prior estimates, 96% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its properties. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its properties. In addition, the Company realized 9.5 million BOE in net upward revisions to its proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. +The Company’s proved developed oil and natural gas reserves increased 56% from 123.5 million BOE at December 31, 2020 to 193.3 million BOE at December 31, 2021. The Company’s proved developed oil and natural gas reserves increased by 101.2 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021, resulting in a net increase of 69.8 million BOE. The Company added 22.4 million BOE in proved developed reserves through extensions and discoveries during 2021, which resulted from new well locations drilled during 2021 to establish proved developed reserves. The Company realized approximately 33.8 million BOE in net upward revisions to prior estimates, 97% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its producing properties. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its producing properties. In addition, the Company converted 40.1 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin during 2021, primarily in the Company’s Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. In addition, the Company realized 4.9 million BOE in net upward revisions to its proved developed reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. +The Company’s proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at December 31, 2020 to 130.1 million BOE at December 31, 2021. The Company added 26.9 million BOE in proved undeveloped reserves through extensions and discoveries during 2021, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. The Company realized approximately 8.1 million BOE in net upward revisions to its prior estimates of proved undeveloped reserves, 90% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its proved undeveloped locations. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its proved undeveloped locations. In addition, the Company realized 4.6 million BOE in net upward revisions to its proved undeveloped reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. During 2021, the Company also converted 40.1 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin during 2021, as noted above. +At December 31, 2021, the Company’s proved reserves were comprised of 56% oil and 44% natural gas and were approximately 60% proved developed and 40% proved undeveloped. This increase in the Company’s proved developed reserves to 60% of its total proved reserves at December 31, 2021 reflected a significant change in the Company’s percentage of proved developed reserves, as compared to 46% and 42% proved developed reserves at December 31, 2020 and 2019, respectively. +The Company’s proved oil and natural gas reserves increased to 270.3 million BOE at December 31, 2020 from 252.5 million BOE at December 31, 2019. The Company’s proved oil and natural gas reserves increased by 45.3 million BOE and the Company produced 27.5 million BOE during the year ended December 31, 2020, resulting in a net increase of 17.8 million BOE. The Company added 35.3 million BOE in proved reserves through extensions and discoveries during 2020, of which 15.2 million BOE resulted from new well locations drilled during 2020 to establish proved developed reserves and 20.1 million BOE consisted primarily of new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2020. The Company also realized 9.8 million BOE in net upward revisions to prior estimates at December 31, 2020, which included positive revisions to prior estimates of 31.2 million BOE attributable primarily to revisions to prior forecasts resulting from better-than-expected well performance during 2020, which was offset by negative revisions to prior estimates of 21.4 million BOE primarily resulting from lower weighted oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. The Company’s proved developed oil and natural gas reserves increased to 123.5 million BOE at December 31, 2020 from 105.7 million BOE at December 31, 2019, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2021, 2020 and 2019 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Basin. At December 31, 2020, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 46% proved developed and 56% proved undeveloped. +The Company’s proved oil and natural gas reserves increased to 252.5 million BOE at December 31, 2019 from 215.3 million BOE at December 31, 2018. The Company’s proved oil and natural gas reserves increased by 61.4 million BOE and the Company produced 24.2 million BOE during the year ended December 31, 2019, resulting in a net increase of 37.2 million BOE. The Company’s proved oil and natural gas reserves increased by 58.6 million BOE during 2019 as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 5.1 million BOE during 2019 as a result of upward revisions of prior estimates, which were attributable to better-than-expected well performance from certain wells, but which were also partially offset by downward revisions attributable to the lower weighted average oil and natural gas prices used to estimate proved reserves in 2019, as compared to 2018. The Company’s proved oil and natural gas reserves decreased 2.3 million BOE in 2019 as a result of net divestitures of minerals-in-place primarily in the Eagle Ford Shale in South Texas and the Haynesville Shale in Northwest Louisiana. The Company’s proved developed oil and natural gas reserves increased to 105.7 million BOE at December 31, 2019 from 94.3 million BOE at December 31, 2018, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2019, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 42% proved developed and approximately 58% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2021, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, the comparable average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, the comparable average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2021, 2020 and 2019 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2021, 2020 and 2019 (in thousands). +Year Ended December 31, +2021 2020 2019 +Future cash inflows $ 15,174,065 $ 6,587,343 $ 8,771,595 +Future production costs (4,588,677) (2,606,956) (3,087,142) +Future development costs (1,251,581) (1,075,317) (1,638,744) +Future income tax expense (1,836,009) (228,848) (479,011) +Future net cash flows 7,497,798 2,676,222 3,566,698 +10% annual discount for estimated timing of cash flows (3,122,373) (1,091,823) (1,532,715) +Standardized measure of discounted future net cash flows $ 4,375,425 $ 1,584,399 $ 2,033,983 +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2021, 2020 and 2019 (in thousands). +Year Ended December 31, +2021 2020 2019 +Balance, beginning of period $ 1,584,399 $ 2,033,983 $ 2,250,613 +Net change in sales and transfer prices and in production (lifting) costs related to future production 3,347,910 (1,126,777) (622,710) +Changes in estimated future development costs (238,871) 177,074 (284,748) +Sales and transfers of oil and natural gas produced during the period (1,412,591) (546,169) (682,747) +Net purchases (divestitures) of reserves in place 178,695 1,803 (28,849) +Net change due to extensions and discoveries 620,235 296,617 733,208 +Net change due to revisions in estimates of reserves quantities 786,061 93,066 63,436 +Previously estimated development costs incurred during the period 240,664 253,165 258,593 +Accretion of discount 165,799 240,728 237,548 +Other 1,737 16 (4,861) +Net change in income taxes (898,613) 160,893 114,500 +Standardized measure of discounted future net cash flows $ 4,375,425 $ 1,584,399 $ 2,033,983 +F-42 \ No newline at end of file diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/filing_metadata.csv b/raw/filings/0001520006/2021/0001520006-22-000065/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..24834d6acb7e2ef129f19a33057f5dc380609f7c --- /dev/null +++ b/raw/filings/0001520006/2021/0001520006-22-000065/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2022-02-28,2021-12-31,2022-03-01T02:14:51.000Z,0001520006-22-000065,mtdr-20211231.htm,10-K,15304072,1,1,https://www.sec.gov/Archives/edgar/data/1520006/000152000622000065/mtdr-20211231.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000622000065/,2021,2021,1 diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/item1.txt b/raw/filings/0001520006/2021/0001520006-22-000065/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..54727dba0c2750b0abe625f25513c93725981569 --- /dev/null +++ b/raw/filings/0001520006/2021/0001520006-22-000065/item1.txt @@ -0,0 +1,601 @@ +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, our midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo; +• maintain our financial discipline; +2 +Table of Contents +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs and do so in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas prices improved significantly during 2021. These factors, along with the successful execution of our business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2021, as well as to increases in our oil and natural gas revenues and cash flows. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down borrowings, initiating and increasing a quarterly cash dividend and earning performance incentives from Five Point. Further, we concluded several important financing transactions in 2021, including extending the maturity of and significantly increasing the borrowing base under our Credit Agreement (as defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved several important milestones in 2021, including the addition of produced water disposal capacity and being awarded several new customer contracts. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2021 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2021, we achieved record oil, natural gas and average daily oil equivalent production. In 2021, we produced 17.8 million Bbl of oil, an increase of 12%, as compared to 15.9 million Bbl of oil produced in 2020. We also produced 81.7 Bcf of natural gas, an increase of 18% from 69.5 Bcf of natural gas produced in 2020. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended December 31, 2020. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2021 as compared to 58% in 2020. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, an increase of 20% from 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, at December 31, 2020. The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and PV-10 were primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2021, proved developed reserves included 102.2 million Bbl of oil and 546.2 Bcf of natural gas, and proved undeveloped reserves included 79.1 million Bbl of oil and 306.4 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 60% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2021. Proved developed reserves and proved oil reserves comprised 46% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2020. The improvement in proved developed reserves as a percentage of our total proved oil and natural gas reserves to 60% at December 31, 2021 from 46% at December 31, 2020 was primarily attributable to the development and conversion of approximately 40.1 million BOE of our proved undeveloped reserves to proved developed reserves in the Delaware Basin in 2021. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage +3 +Table of Contents +operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2022. +We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin in 2021, including 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells. At December 31, 2021, our total acreage position in the Delaware Basin was approximately 237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust asset areas in Loving County, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 19% to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020. We expect our Delaware Basin production to increase in 2022 as we continue the delineation and development of these asset areas. +During 2021, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +• the second group of Rodney Robinson wells in the western portion of our Antelope Ridge asset area, in March 2021; these four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in 11 months of production; +• the first 13 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a staggered fashion during April and May 2021; these 13 Voni wells have produced in aggregate approximately 5.2 million BOE in eight months of production; +• four wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in July 2021; these four wells have produced in aggregate approximately 0.7 million BOE in seven months of production; +• the second group of 13 Boros wells in the eastern portion of the Stateline asset area in a staggered fashion at various times primarily throughout September 2021; these 13 Boros wells have produced in aggregate approximately 2.2 million BOE in five months of production; and +• nine additional wells in the Greater Stebbins Area in December 2021. +In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2021 included: +• the fully realized transition to drilling longer laterals, whereby 98% of the operated horizontal wells we turned to sales in 2021 had lateral lengths of two miles or greater, as compared to 74% in 2020, 8% in 2019 and only one two-mile lateral in 2018; +• the continuing improvement in capital efficiency as demonstrated by our average drilling and completion costs for all operated horizontal wells turned to sales of approximately $670 per lateral foot in 2021, a decrease of 21% as compared to $850 per lateral foot in 2020, a decrease of 42% as compared to average drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 56% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018; +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2021 of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021, despite the acceleration of 11 Voni well completions forward into the fourth quarter of 2021 and the addition of a fifth operated drilling rig; +• record-low annual unit operating costs for lease operating expenses of $3.46 per BOE; +• general and administrative expenses of $3.06 per BOE, which were the second lowest general and administrative expenses we have achieved on an annual basis, as compared to a record low $2.27 per BOE in 2020. These 2021 general and administrative expenses were achieved despite the impact of increased cash-settled stock compensation costs and the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time. +4 +Table of Contents +Capital Resources and Financing Highlights +During 2021, we achieved several significant and important capital resources objectives we set at the beginning of the year. These objectives included: +• the generation of free cash flow in all four quarters of 2021; +• the net repayment of $340.0 million in borrowings under our revolving credit facility, resulting in outstanding borrowings of $100.0 million at December 31, 2021; +• the adoption of a dividend policy in the first quarter of 2021 pursuant to which we initiated a quarterly cash dividend of $0.025 per share of common stock and the subsequent amendment of that dividend policy in the fourth quarter of 2021, pursuant to which we doubled the quarterly cash dividend to $0.05 per share of common stock; and +• the receipt of $48.6 million in performance incentives directly from Five Point; +In addition, we concluded several important financing transactions in 2021 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the closing of our fourth amended and restated credit agreement (the “Credit Agreement”) in November 2021 to (i) extend the maturity date by three years to October 31, 2026 from October 31, 2023 previously, (ii) increase the borrowing base by 50% to $1.35 billion, as compared to $900.0 million previously, (iii) reaffirm the elected borrowing commitment at $700.0 million, (iv) reaffirm the maximum facility amount at $1.5 billion and (v) add three new banks to our lending group; and +• the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in June 2021 to increase the lender commitments under the revolving credit facility to $450.0 million from $375.0 million and an accordion feature that provides for potential increases in lender commitments to up to $700.0 million. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +San Mateo achieved strong operating results in 2021, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2020. Volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. +During 2021, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021. +At December 31, 2021, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity in San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large-diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 14 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +5 +Table of Contents +Environmental, Social and Governance (“ESG”) Initiatives +We maintain an active ESG program and continued working in 2021 to improve upon our various ESG efforts. In May 2021, we published sustainability metrics aligned with standards developed by the Sustainability Accounting Standards Board (“SASB”), which we subsequently updated in July 2021. In December 2021, we issued our inaugural Sustainability Report highlighting the results of our 2020 ESG progress and achievements. +In 2020, we grew gross operated oil production by 13% and gross operated natural gas production by 19%, as compared to 2019, while still reducing our environmental impact and continuing our strong safety record. Highlights from our 2020 ESG initiatives include: +• Decreased emissions intensity by 19% and flaring intensity by 38%, as compared to 2019; +• Decreased consumption of fresh water by 49%, as compared to 2019; +• Transported 96% of operated produced water and 65% of operated produced oil by pipeline; +• Incurred no employee lost time incidents during more than 2.1 million employee man-hours from 2017 to 2020; +• Provided approximately 15,000 hours of employee continuing education, equating to approximately 55 hours per employee; and +• Revised the mandate of the Board of Directors’ Environmental, Social and Corporate Governance Committee to enhance the focus, oversight and support for our ESG efforts and to measure improvements. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2021, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2021. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +237,200 124,800 944 468.1 4,381 1,534 312,018 58.6 80,534 +South Texas: +Eagle Ford (5) +27,400 25,100 131 110.5 208 175 5,663 100.0 2,126 +Northwest Louisiana +Haynesville 16,700 9,100 233 18.3 161 15 4,848 82.6 3,334 +Cotton Valley (6) +16,100 14,900 63 39.6 154 35 868 100.0 182 +Area Total (7) +19,100 17,700 296 57.9 315 50 5,716 85.3 3,516 +Total 283,700 167,600 1,371 636.5 4,904 1,759 323,397 59.8 86,176 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2021. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2021, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2021, these engineered drilling locations included 358 gross (136 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, in the Delaware Basin and only eight gross (0.4 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. At December 31, 2021, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +6 +Table of Contents +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2021. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. In January 2022, the two wells and associated acreage in Zavala County, Texas, which included 55 gross (55 net) engineered locations, were divested. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2021, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2021, we also were the operator for almost all of our Eagle Ford acreage and approximately half of our Haynesville acreage. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2021, our total acreage position in Southeast New Mexico and West Texas was approximately 237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 39,700 gross (22,600 net) acres in our Ranger asset area in Lea County, 64,500 gross (26,000 net) acres in our Arrowhead asset area in Eddy County, 47,500 gross (25,900 net) acres in our Rustler Breaks asset area in Eddy County, 24,700 gross (15,700 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,700 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 42,900 gross (20,500 net) acres in our Twin Lakes asset area in Lea County at December 31, 2021. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2021, our acreage position in the Delaware Basin was approximately 75% held by existing production. Excluding the Twin Lakes asset area, where at December 31, 2021 we had drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 86% held by existing production at December 31, 2021. +During the year ended December 31, 2021, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin, including 47 +7 +Table of Contents +gross (44.2 net) operated horizontal wells and 50 gross (4.0 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2021, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2021. Our average daily oil equivalent production from the Delaware Basin increased approximately 19% to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020. +At December 31, 2021, approximately 96% of our estimated total proved oil and natural gas reserves, or 312.0 million BOE, was attributable to the Delaware Basin, including approximately 177.1 million Bbl of oil and 809.3 Bcf of natural gas, a 19% increase, as compared to 261.9 million BOE for the year ended December 31, 2020. Our Delaware Basin proved reserves at December 31, 2021 comprised approximately 98% of our proved oil reserves and 95% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and 96% of our proved natural gas reserves at December 31, 2020. +At December 31, 2021, we had identified 4,381 gross (1,534 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,204 gross (1,350 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2021, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2021, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2021, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2021, these potential future drilling locations included 358 gross (136 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves. +At December 31, 2021, we were operating five drilling rigs in the Delaware Basin. At February 22, 2022, we had contracted a sixth drilling rig to begin drilling operations on recently acquired acreage in the western portion of our Ranger asset area in Lea County, New Mexico. We expect to operate six drilling rigs across our various Delaware Basin asset areas throughout the remainder of 2022, but these six drilling rigs are expected to have an increased focus on our Rustler Breaks, Antelope Ridge and Ranger asset areas in 2022, as compared to 2021. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2022. +Antelope Ridge Asset Area - Lea County, New Mexico +At the end of the first quarter of 2021, we achieved the first of the five operational milestones we set for Matador in 2021 when we turned to sales four gross (3.8 net) wells on the Rodney Robinson leasehold. These wells were the second group of wells drilled on the Rodney Robinson leasehold, which was acquired in the BLM Acquisition. We did not turn to sales any other operated wells in other portions of the Antelope Ridge asset area during 2021, although we did participate in the drilling and completion of 20 gross (1.1 net) non-operated wells that were turned to sales in the Antelope Ridge asset area during 2021. +The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. The four Rodney Robinson wells, which included two Wolfcamp A-XY completions and two Third Bone Spring +8 +Table of Contents +completions, were turned to sales late in the first quarter of 2021 and were all two-mile laterals. These four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in approximately 11 months of production despite being produced on restricted chokes throughout their early producing lives. We drilled nine additional Rodney Robinson wells in the fall of 2021, and these nine wells are expected to be turned to sales late in the first quarter of 2022. +We turned to sales the initial six Rodney Robinson wells in the western portion of the Antelope Ridge asset area in late March 2020. In aggregate, these six wells have produced approximately 4.3 million BOE in approximately 22 months of production. +Rustler Breaks Asset Area - Eddy County, New Mexico +In the Rustler Breaks asset area, we turned to sales 13 gross (0.9 net) non-operated wells during 2021. We did not turn to sales any operated wells during 2021, but at December 31, 2021, we had drilled or were drilling six operated wells in the Rustler Breaks asset area, all of which are expected to be turned to sales in the second quarter of 2022. We expect the Rustler Breaks asset area to be an area of increased operational focus for Matador throughout 2022. +Arrowhead Asset Area - Eddy County, New Mexico +In the Arrowhead asset area, we turned to sales 13 gross (11.5 net) operated wells and 14 gross (1.6 net) non-operated wells during 2021. +During the third quarter of 2021, we achieved the third of the five operational milestones we set for Matador in 2021 when we turned to sales four wells, all of which were two-mile laterals completed in the Second Bone Spring formation, in the Greater Stebbins Area. These four wells have produced in aggregate approximately 0.7 million BOE in seven months of production. At the end of the fourth quarter of 2021, we achieved the fifth and final operational milestone we set for Matador in 2021 when we turned to sales nine wells, all of which were two-mile laterals completed in the Third Bone Spring, Wolfcamp A-XY and Wolfcamp B formations, in the Greater Stebbins Area in December 2021. +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales two gross (1.3 net) operated wells and three gross (0.4 net) non-operated wells. We did not turn to sales any operated or non-operated wells in the Twin Lakes asset area during 2021. +We were pleased with the performance from the first two Uncle Ches wells turned to sales in the Second Bone Spring in the Ranger asset area in the first quarter of 2021. In aggregate, these two wells tested 4,053 BOE per day (90% oil) during 24-hour initial potential (“IP”) tests conducted after these wells were equipped with electric submersible pumps (“ESP”). The high (90%) oil cut and low water cut (approximately one Bbl of water per Bbl of oil produced) exhibited by these wells should enhance their economics. We drilled two additional Uncle Ches wells in the Ranger asset area in the fall of 2021, also Second Bone Spring completions, which were turned to sales in mid-January 2022. +Stateline Asset Area - Eddy County, New Mexico +We operated two drilling rigs in our Stateline asset area for the majority of 2021. In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,900 gross and net leasehold acres prospective for multiple geologic targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage has shown to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We have been developing this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.3-mile laterals on the western side of the leasehold. We began drilling operations in the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we turned to sales our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. In aggregate, the first 13 Boros wells have produced approximately 7.2 million BOE in approximately 15 months of production. +After finishing drilling operations on the first 13 Boros wells in 2020, we began drilling operations on the Voni tract in the western portion of the Stateline asset area, and in the second quarter of 2021, we achieved the second of the five operational milestones we set for Matador in 2021 when we turned to sales our first 13 gross (12.7 net) wells on the Voni tract in the western portion of the Stateline asset area. The 13 Voni wells had completed lateral lengths of approximately 12,000 feet, or about 2.3-miles, making them the longest laterals Matador has completed to date. The 13 Voni wells included one First Bone Spring completion, four Second Bone Spring completions, four Wolfcamp A-XY completions and four Wolfcamp A-Lower completions. Of particular note, the Voni Federal #216H well, a Wolfcamp A-Lower completion, tested 5,073 BOE per day (60% oil), which was the highest 24-hour IP Matador has achieved to date in any formation in the Delaware Basin. These 13 Voni wells have produced in aggregate approximately 5.2 million BOE in approximately eight months of production, despite a number of these wells being produced on restricted chokes early in their producing lives. +After finishing drilling operations on the first 13 Voni wells, we began drilling operations on the next 13 Boros wells, and in the third quarter of 2021, we achieved the fourth of the five operational milestones we set for Matador in 2021 when we +9 +Table of Contents +turned to sales our second group of 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. These 13 Boros wells have produced in aggregate approximately 2.2 million BOE in five months of production. Drilling and completion costs for the 26 Stateline wells turned to sales during 2021 averaged $628 per completed lateral foot, the lowest costs we have achieved in any of our asset areas. +In addition, during 2021, we drilled and completed our second group of 11 wells on the Voni tract on the western portion of the Stateline leasehold. These 11 Voni wells are expected to have completed lateral lengths of approximately 12,000 feet and were turned to sales in the first quarter of 2022. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we turned to sales two gross (1.9 net) operated wells during 2021. At December 31, 2021, we were in the process of completing three two-mile lateral wells in the Second Bone Spring formation, and these three wells were turned to sales in February 2022. +South Texas — Eagle Ford Shale and Other Formations +The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. +At December 31, 2021, our properties included approximately 27,400 gross (25,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2021. +We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2021. In fact, as of December 31, 2021, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 12% to 2,126 BOE per day, including 1,528 Bbl of oil per day and 3.6 MMcf of natural gas per day, during 2021, as compared to 2,412 BOE per day, including 1,840 Bbl of oil per day and 3.4 MMcf of natural gas per day, during 2020. For the year ended December 31, 2021, 2% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 3% for the year ended December 31, 2020. +At December 31, 2021, approximately 2% of our estimated total proved oil and natural gas reserves, or 5.7 million BOE, was attributable to the Eagle Ford shale, including approximately 4.1 million Bbl of oil and 9.1 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2021, essentially unchanged from December 31, 2020. +At December 31, 2021, we had identified 208 gross (175 net) engineered locations for potential future drilling on our Eagle Ford acreage, including 55 gross (55 net) engineered locations in Zavala County that were divested in January 2022. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to almost two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors. +These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2021, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the prospectivity of these intervals. +10 +Table of Contents +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated Haynesville shale wells that were turned to sales in 2021. In the first quarter of 2020, we leased 2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained royalty interests ranging from 18% to 20%. This lessee turned to sales four Haynesville shale wells drilled on these interests in the first half of 2021. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2022. +At December 31, 2021, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including 16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,800 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2021. +For the year ended December 31, 2021, approximately 4% of our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 7% of our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2021, approximately 9% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 17% of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to these properties. At December 31, 2021, approximately 2% of our estimated total proved reserves, or 5.7 million BOE, was attributable to our properties in Northwest Louisiana. +At December 31, 2021, we had identified 161 gross (15 net) engineered locations for potential future drilling in the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to two miles, with most being two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other factors. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 22, 2022, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through February 22, 2022, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021, and we may earn up to the remaining $14.7 million in San Mateo performance incentives over the next year relating to the formation of San Mateo. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15- +11 +Table of Contents +year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives over the next several years , plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of 2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives from Five Point. At February 22, 2022, we had received $33.9 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2021, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +In September 2020, San Mateo completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2021, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area. +In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2021, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2021, San Mateo gathered approximately 86.1 Bcf of natural gas, an increase of 17%, as compared to 73.9 Bcf of natural gas gathered during the year ended December 31, 2020. In addition, during the year ended December 31, 2021, San Mateo processed approximately 77.6 Bcf of natural gas at the Black River Processing Plant, an increase of 28%, as compared to 60.8 Bcf of natural gas processed during the year ended +12 +Table of Contents +December 31, 2020. Natural gas gathering and processing volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +In 2020, San Mateo completed and placed into service (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2021, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. +At December 31, 2021, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2021, the San Mateo Oil Pipeline Systems had throughput of approximately 14.9 million Bbl of oil, an increase of 28%, as compared to throughput of approximately 11.6 million Bbl of oil during the year ended December 31, 2020. +Produced Water Gathering and Disposal Assets +During 2021, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to three. In addition to its three commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 22, 2022, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 22, 2022, San Mateo had designed disposal capacity of approximately 370,000 Bbl of produced water per day. +During the year ended December 31, 2021, San Mateo handled approximately 101.4 million Bbl of produced water, an increase of 20%, as compared to approximately 84.8 million Bbl of produced water handled during the year ended December 31, 2020. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo. +13 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2021, 2020 and 2019. +Year Ended December 31, +2021 2020 2019 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 17,840 15,931 13,984 +Natural gas (Bcf) 81.7 69.5 61.1 +Total oil equivalent (MBOE) (1) +31,454 27,514 24,164 +Average daily production (BOE/d) (1) +86,176 75,175 66,203 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 67.58 $ 37.38 $ 54.34 +Oil, with realized derivatives (per Bbl) $ 56.70 $ 39.83 $ 54.98 +Natural gas, without realized derivatives (per Mcf) $ 6.06 $ 2.14 $ 2.17 +Natural gas, with realized derivatives (per Mcf) $ 5.74 $ 2.14 $ 2.18 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 5.69 $ 3.39 $ 3.82 +Lease operating $ 3.46 $ 3.81 $ 4.85 +Plant and other midstream services operating $ 1.95 $ 1.51 $ 1.52 +Depletion, depreciation and amortization $ 10.97 $ 13.15 $ 14.51 +General and administrative $ 3.06 $ 2.27 $ 3.31 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 17,279 558 — 3 17,840 +Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7 +Total oil equivalent (MBOE) (3) +29,395 776 1,217 66 31,454 +Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 47,339 1,528 — 9 48,876 +Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8 +Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176 +Average Sales Prices (4) +Oil (per Bbl) $ 67.65 $ 65.41 $ — $ 64.40 $ 67.58 +Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06 +Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 15,254 674 — 3 15,931 +Natural gas (Bcf) 56.8 1.2 11.0 0.5 69.5 +Total oil equivalent (MBOE) (3) +24,713 883 1,835 83 27,514 +Percentage of total annual net production 89.8 % 3.2 % 6.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 41,678 1,840 — 8 43,526 +Natural gas (MMcf/d) 155.1 3.4 30.1 1.3 189.9 +Total oil equivalent (BOE/d) 67,522 2,412 5,015 226 75,175 +Average Sales Prices (4) +Oil (per Bbl) $ 37.38 $ 37.42 $ 28.77 $ 38.31 $ 37.38 +Natural gas (per Mcf) $ 2.23 $ 2.82 $ 1.66 $ 1.69 $ 2.14 +Total oil equivalent (per BOE) $ 28.19 $ 32.56 $ 9.94 $ 11.09 $ 27.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.52 $ 20.52 $ 4.71 $ 19.39 $ 5.09 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 12,843 1,136 — 5 13,984 +Natural gas (Bcf) 44.7 2.0 13.9 0.5 61.1 +Total oil equivalent (MBOE) (3) +20,294 1,463 2,316 91 24,164 +Percentage of total annual net production 84.0 % 6.0 % 9.6 % 0.4 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 35,184 3,113 — 15 38,312 +Natural gas (MMcf/d) 122.5 5.4 38.1 1.4 167.4 +Total oil equivalent (BOE/d) 55,599 4,009 6,345 250 66,203 +Average Sales Prices (4) +Oil (per Bbl) $ 53.95 $ 58.71 $ — $ 52.89 $ 54.34 +Natural gas (per Mcf) $ 2.11 $ 3.45 $ 2.16 $ 2.17 $ 2.17 +Total oil equivalent (per BOE) $ 38.80 $ 50.22 $ 12.99 $ 15.22 $ 36.93 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.22 $ 15.27 $ 4.36 $ 22.43 $ 5.81 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021 increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31, 2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the year ended December 31, 2020. +Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020 increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31, 2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for the year ended December 31, 2019. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2021. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 81% in all wells that we operated at December 31, 2021. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +784 388.4 160 79.7 944 468.1 +South Texas: +Eagle Ford (2) +128 107.5 3 3.0 131 110.5 +Northwest Louisiana: +Haynesville — — 233 18.3 233 18.3 +Cotton Valley (3) +1 1.0 62 38.6 63 39.6 +Area Total 1 1.0 295 56.9 296 57.9 +Total 913 496.9 458 139.6 1,371 636.5 +__________________ +(1) Includes 212 gross (67.5 net) vertical wells that were acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2021, 2020 and 2019. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +17 +Table of Contents +At December 31, (1) +2021 2020 2019 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 181,306 159,949 147,991 +Natural Gas (Bcf) 852.5 662.3 627.2 +Total (MBOE) (3) +323,397 270,332 252,531 +Estimated proved developed reserves: +Oil (MBbl) 102,233 69,647 59,667 +Natural Gas (Bcf) 546.2 323.2 276.3 +Total (MBOE) (3) +193,262 123,507 105,710 +Percent developed 59.8 % 45.7 % 41.9 % +Estimated proved undeveloped reserves: +Oil (MBbl) 79,073 90,301 88,324 +Natural gas (Bcf) 306.4 339.1 351.0 +Total (MBOE) (3) +130,135 146,825 146,821 +Standardized Measure (4) (in millions) +$ 4,375.4 $ 1,584.4 $ 2,034.0 +PV-10 (5) (in millions) +$ 5,347.6 $ 1,658.0 $ 2,248.2 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas, for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas and for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2021, 2020 and 2019 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2021, 2020 and 2019 were, in millions, $972.2, $73.6 and $214.2, respectively. +Our estimated total proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. This increase in proved oil and natural gas reserves was primarily attributable to (i) our delineation and development operations in the Delaware Basin during 2021 and (ii) the 75% increase in oil prices and the 81% increase in natural gas prices used to estimate total proved reserves at December 31, 2021, as compared to December 31, 2020. We added 33.1 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 16.3 million BOE to proved reserves at a future date. We realized approximately 41.9 million BOE in net upward revisions to prior estimates, 96% of which were attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our properties. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our properties. In addition, we realized 9.5 million BOE in net upward revisions to our proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. +Our proved oil reserves grew 13% from approximately 159.9 million Bbl at December 31, 2020 to approximately 181.3 million Bbl at December 31, 2021. Our proved natural gas reserves increased 29% from 662.3 Bcf at December 31, 2020 to +18 +Table of Contents +852.5 Bcf at December 31, 2021. Our proved reserves to production ratio at December 31, 2021 was 10.3, an increase of 5% from 9.8 at December 31, 2020. +The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2021 were $63.04 per Bbl and $3.60 per MMBtu, an increase of 75% and 81%, respectively, as compared to average oil and natural gas prices of $36.04 per Bbl and $1.99 per MMBtu used to estimate proved reserves at December 31, 2020. Our total proved reserves were made up of 56% oil and 44% natural gas at December 31, 2021 and 59% oil and 41% natural gas at December 31, 2020. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2021. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2020 123,507 +Extensions and discoveries 22,427 +Net acquisitions of minerals-in-place 4,907 +Revisions of prior estimates 33,804 +Production (31,454) +Conversion of proved undeveloped to proved developed 40,071 +As of December 31, 2021 193,262 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 56% from 123.5 million BOE at December 31, 2020 to 193.3 million BOE at December 31, 2021. We added 22.4 million BOE in proved developed reserves through extensions and discoveries during 2021, which resulted from new well locations drilled during 2021 to establish proved reserves. We realized approximately 33.8 million BOE in net upward revisions to prior estimates, 97% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our producing properties. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our producing properties. In addition, we converted 40.1 million BOE of our proved undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. In addition, we realized 4.9 million BOE in net upward revisions to our proved developed reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. These cumulative net upward revisions of 101.2 million BOE to our proved developed reserves exceeded by 3.2 times our total oil and natural gas production of 31.5 million BOE in 2021. +Our proved developed oil reserves increased 47% from 69.6 million Bbl at December 31, 2020 to 102.2 million Bbl at December 31, 2021. Our proved developed natural gas reserves increased 69% from 323.2 Bcf at December 31, 2020 to 546.2 Bcf at December 31, 2021. Proved developed reserves constituted 60% of our total proved oil and natural gas reserves at December 31, 2021, as compared to 46% at December 31, 2020. +19 +Table of Contents +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2021. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2020 146,825 +Extensions and discoveries 10,647 +Net acquisitions of minerals-in-place 4,622 +Revisions of prior estimates 8,112 +Conversion of proved undeveloped to proved developed (40,071) +As of December 31, 2021 130,135 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at December 31, 2020 to 130.1 million at December 31, 2021. We added 26.9 million BOE in proved undeveloped reserves through extensions and discoveries during 2021, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2021 but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. We realized approximately 8.1 million BOE in net upward revisions to our prior estimates of proved undeveloped reserves, 90% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our proved undeveloped locations. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our proved undeveloped locations. In addition, we realized 4.6 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. During 2021, we also converted 40.1 million BOE of our proved undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. +At December 31, 2021, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2021 within five years of booking these reserves. The following table sets forth, since 2018, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2018 16,009 61.7 26,283 $ 356,830 +2019 13,832 58.8 23,629 318,609 +2020 16,256 76.1 28,944 257,590 +2021 23,965 96.6 40,071 240,664 +Total 70,062 293.2 118,927 $ 1,173,693 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +20 +Table of Contents +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2021. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 177,137 809.3 312,018 $ 4,268.7 $ 5,217.2 +South Texas: +Eagle Ford (5) +4,146 9.1 5,663 78.8 96.2 +Northwest Louisiana +Haynesville — 29.1 4,848 26.3 32.2 +Cotton Valley (6) +23 5.0 868 1.6 2.0 +Area Total 23 34.1 5,716 27.9 34.2 +Total 181,306 852.5 323,397 $ 4,375.4 $ 5,347.6 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2021 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2021 were approximately $972.2 million. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Reserves Manager was primarily responsible for overseeing the preparation of our reserves estimates in 2021. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional +21 +Table of Contents +Engineer in the state of Texas and has over nine years of industry experience. Our Reserves Manager works under the direct supervision of our Senior Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 14 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and U.S. generally accepted accounting principles (“GAAP”) requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2021. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 184,000 93,000 53,200 31,800 237,200 124,800 +South Texas: +Eagle Ford 27,400 25,100 — — 27,400 25,100 +Northwest Louisiana: +Haynesville 16,700 9,100 — — 16,700 9,100 +Cotton Valley 16,100 14,900 — — 16,100 14,900 +Area Total (1) +19,100 17,700 — — 19,100 17,700 +Total 230,500 135,800 53,200 31,800 283,700 167,600 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2021 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2027 and beyond totals 6,700 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2021. +Acres Acres Acres Acres Acres +Expiring 2022 Expiring 2023 Expiring 2024 Expiring 2025 Expiring 2026 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +24,100 11,100 5,500 5,300 8,900 3,100 2,900 2,800 5,200 2,800 +Total 24,100 11,100 5,500 5,300 8,900 3,100 2,900 2,800 5,200 2,800 +__________________ +(1) Approximately 65% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2021, +22 +Table of Contents +our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2021, less than 2% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2021, 2020 and 2019 . +Year Ended December 31, +2021 2020 2019 +Gross Net Gross Net Gross Net +Development Wells +Productive 96 40.2 89 44.5 147 62.0 +Dry — — — — — — +Exploration Wells +Productive 8 8.0 4 3.3 25 13.3 +Dry — — — — — — +Total Wells +Productive 104 48.2 93 47.8 172 75.3 +Dry — — — — — — +At December 31, 2021, we had a total of 31 gross (27.0 net) development wells and two gross (1.1 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, including Russia, Ukraine, China and the Middle East, domestic or global health concerns such as COVID-19, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in +23 +Table of Contents +the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2021, 2020 and 2019, we had three, two and two significant purchasers, respectively, that accounted for approximately 72%, 65% and 67%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals. Although some of these restrictions have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +24 +Table of Contents +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the Bureau of Land Management (“BLM”) to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). In 2019, 2020 and 2021, an environmental group filed three lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit, but the appeal was voluntarily dismissed in 2021. In February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. The BLM has not announced when it will complete the additional NEPA review, and the outcome of that review with regard to the leases at issue and any related drilling permits is uncertain. +25 +Table of Contents +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and gas leasing and permitting decisions by the BLM. In February 2022, the Louisiana federal district court issued an injunction prohibiting the federal government, including the Department of Interior and BLM, from utilizing the challenged social cost of greenhouse gases factor as a part of NEPA reviews. Subsequent to that decision, the federal government submitted filings in the federal district court indicating that the court’s injunction could, among other things, result in an indefinite delay of future lease sales and permit approvals due to inconsistencies between the NEPA analyses and the court’s ruling. +Although some of the restrictions in the Biden Administrative Federal Lease Orders have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation and Social Cost of Carbon Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing +26 +Table of Contents +regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. The Build Back Better Act (H.R. 5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains certain U.S. federal income tax changes and certain additional taxes and fees. +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +27 +Table of Contents +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures to protect the environment and work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (the “RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore +28 +Table of Contents +facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015 rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and the promulgation of the NWPR. +Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the U.S. Fish and Wildlife Service (the “USFWS”) under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance of NWPs in 2021. The Corps has now issued a new set of NWPs, which would replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but has not elected not to consult with the USFWS. The re-issued NWPs have similarly been subject to the same legal challenges based on the lack of a formal ESA consultation. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris +29 +Table of Contents +Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the New Mexico Oil Conservation Division (the “NMOCD”) implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) has also proposed similar rules and regulations. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our +30 +Table of Contents +ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have an adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +31 +Table of Contents +As of December 31, 2021, approximately 31% of our Delaware Basin acreage position consisted of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions related to the oil and natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2021, we had 286 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for +32 +Table of Contents +company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2020, for example, our employees completed approximately 15,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2021, we estimate our employees have worked approximately 2.7 million combined hours without experiencing a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations to proactively minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +33 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/item13.txt b/raw/filings/0001520006/2021/0001520006-22-000065/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2021/0001520006-22-000065/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/item9a.txt b/raw/filings/0001520006/2021/0001520006-22-000065/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..134a6e787ee6c307d9a8f8ffa11a6c3332559652 --- /dev/null +++ b/raw/filings/0001520006/2021/0001520006-22-000065/item9a.txt @@ -0,0 +1,31 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2021 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2021, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2021 as included herein. +90 +Table of Contents +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2022 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 28, 2022 +92 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/rp_note.txt b/raw/filings/0001520006/2021/0001520006-22-000065/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2021/0001520006-22-000065/rpt_disclosure.txt b/raw/filings/0001520006/2021/0001520006-22-000065/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..6cc4489e17bf12abeee711951b6eeab0212d2da8 --- /dev/null +++ b/raw/filings/0001520006/2021/0001520006-22-000065/rpt_disclosure.txt @@ -0,0 +1,123 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2021, there was not, nor was there proposed +as of December 31, 2021, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% +of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which +are described in “Executive Compensation—Compensation Discussion and Analysis” and “Director Compensation” above. +Working Interest and Overriding Royalty Interest Owners +Joseph Wm. Foran, Chairman and Chief Executive Officer, and certain of Mr. Foran’s affiliated entities (collectively, the “Foran Entities”) are +working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, the Foran Entities are required to pay their +proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Foran Entities are entitled to receive their proportionate share of +revenues from the wells in which they own an interest in the normal course of business. During 2021, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners or overriding royalty interest owners were +approximately $5.5 million (the “Related Net Revenue Payments”). The Related Net Revenue Payments represent less than 1% of our total third-party net revenue payments during 2021. +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2021, our joint +interest billings to the Foran Entities attributable to their share of costs were approximately $2.1 million (the “Related Joint Interest Billings”). The Related Joint Interest Billings represent less than 1% of our total joint +interest billings during 2021. As a result of this ownership by the Foran Entities, from time to time, we will be in a net receivable or net payable position with certain of the Foran Entities. We do not consider any net receivables from the Foran +Entities to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Foran Entities for +potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s relationships and interests in such transactions and all other material facts related to the Related Net Revenue +Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments +and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Joint Venture Relationship +The Company has entered into a joint venture (the “Joint +Venture”) with Spearpoint Resources Company (“Spearpoint”) to generate value through a conventional vertical well development program in our Twin Lakes asset area. An adult child of Mr. Foran is the founder of Spearpoint and +serves as an executive officer and director of Spearpoint. Mr. Foran’s child has a Bachelor of Arts degree in Economics from Princeton University, a Master’s of Science degree in Petroleum Engineering from Texas A&M University and +a Master’s degree in Business Administration from Rice University. Mr. Foran’s child worked for a major oil and gas company as a petroleum petrophysicist and has served for over 10 years and achieved the rank of Major in the United +States Marine Corp Reserve. Mr. Foran’s child may perform shared services to the Joint Venture, for which the Joint Venture would reimburse Spearpoint. +During 2021, the Company made capital contributions to the Joint Venture of seismic data and approximately $4.0 million (the “Capital Contributions”). +The Company did not receive any distributions from the Joint Venture in 2021, and the Joint Venture did not pay Spearpoint for any shared services provided by Mr. Foran’s child, +2022 +Proxy Statement | Matador Resources Company 87 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +although such distributions may be received by the Company or such shared service amounts may be paid by Spearpoint in the future. +The Audit Committee reviewed the terms of the Joint Venture for potential conflicts of interest under the Related Person Transaction Policy, and, after being fully +informed as to Mr. Foran’s relationships and interests in such transactions and all other material facts related to the Joint Venture, determined that such transactions, including the Capital Contributions, were fair to the Company and +recommended such transactions to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions, including the Capital Contributions. +Certain Employment Relationships +Billy E. Goodwin served as an executive officer during 2021 and +currently serves as the Company’s President – Operations. During 2021, two of Mr. Goodwin’s adult children were employees of the Company and had been employees since 2014 and 2015, respectively. One of Mr. Goodwin’s +children resigned in 2021. Each child earned in 2021, and the remaining child that is employed by the Company in 2022 is expected to be compensated in 2022, between $120,000 and $500,000. One of Mr. Goodwin’s children has a Bachelor of +Science degree in Petroleum Engineering from the University of Tulsa and over 11 years of industry experience, including as a regional drilling supervisor for another publicly traded exploration and production company. Mr. Goodwin’s other +child has a Bachelor of Science in Business Administration degree in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He also has over 11 years of +industry experience, including as a drilling fluids engineer for a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment +arrangements for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangements and historical and anticipated compensation of Mr. Goodwin’s +adult children, and all other material facts related to the relationship, determined that the employment arrangements were fair to the Company and recommended the employment arrangements to the full Board for approval and ratification. The Board +subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s sister-in-law has been an employee of the Company since 2016 and earned in 2021, and is expected to be compensated in 2022, between $120,000 and $250,000. +Mr. Baribault’s sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist +University Legal Assistants Program. She has over 39 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person +Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s +sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the +employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of +Mr. Foran has been an employee of the Company since 2015 and earned in 2021, and is expected to be compensated in 2022, between $120,000 and $250,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development +and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than 10 years of industry experience, including with another publicly traded exploration and production company. Another adult child of +Mr. Foran was employed as a consultant to the Company in 2021 and was compensated, and is expected to be compensated in 2022, between $120,000 and $250,000. Mr. Foran’s child has a degree from Yale University and a Master’s +degree in Business Administration from the University of Chicago and also worked for a major oil and gas company for a number of years. The Audit Committee reviewed the terms of the employment arrangement and the consulting arrangement for potential +conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and the consulting arrangement and historical and anticipated compensation of Mr. Foran’s +adult children, and all other material facts related to the relationship, determined that the employment arrangement and the consulting arrangement each was fair to the Company and +88 Matador Resources Company | 2022 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +recommended the employment arrangement and the consulting arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement and +such consulting arrangement. +Procedures for Approval of Related Person Transactions +Pursuant to the Related Person Transaction Policy as in effect +as of December 31, 2021, a “Related Person Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related +transactions, or any material amendment to any such transaction, in which a Related Person (as defined below) has or will have a direct or indirect material interest and in which we are a participant, other than: +• +a transaction involving compensation of directors that is required to be reported in our proxy statement under Item 402 of +the SEC’s compensation disclosure requirements (“Item 402”); +• +any employment by us of an executive officer if: +¡ +the related compensation is required to be reported in our proxy statement under Item 402; or +¡ +the executive officer is not an “immediate family member” of another executive officer or director of the +Company, the related compensation would be reported in our proxy statement under Item 402 if the executive officer was a “named executive officer” and the Compensation Committee approved (or recommended that the Board approve) such +compensation; +• +a transaction with a Related Person involving less than $120,000; +• +a transaction in which the interest of the Related Person arises solely from the ownership of a class of our equity +securities and all holders of that class receive the same benefit on a pro rata basis; +• +a transaction in which a Related Person has an indirect interest solely as a result of being (a) a director or, +together with all other Related Persons, a less than 10% beneficial owner of an equity interest in another entity, or both, or (b) a limited partner in a partnership in which the Related Person, together with all other Related Persons, has an +interest of less than 10%; +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that +involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority; +• +any transaction with another company at which a Related Person’s only relationship is as an employee (other than an +executive officer), if the aggregate amount involved does not exceed the greater of $1,000,000, or 2% of that company’s total annual revenues; +• +any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a +Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the lesser of $1,000,000, or 2% of the charitable organization’s total annual receipts; or +• +any transaction with another publicly traded company where the Related Person’s interest arises solely from beneficial +ownership of more than 5% of our Common Stock and ownership of a non-controlling interest in the other publicly traded company. +“Related Person” means: +• +any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors +or nominees for director; +• +any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, +sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law or person residing (other than a tenant or employee) in the home of a director, nominee for director, executive officer or a beneficial owner of more than 5% of +our Common Stock; and +2022 +Proxy Statement | Matador Resources Company 89 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +• +any entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a +general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Person Transaction Policy, the Audit Committee must review all material facts of each Related Person Transaction and recommend either approval +or disapproval of the Related Person Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Person Transaction, the Audit Committee must, after reviewing all +material facts of the Related Person Transaction and the Related Person’s relationship and interest, determine whether the Related Person Transaction is fair to the Company. Further, the policy requires that all Related Person Transactions be +disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +90 Matador Resources Company | 2022 Proxy Statement +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/filing.txt b/raw/filings/0001520006/2022/0001520006-23-000056/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..062a10880c6fc9b942919559007fa637cd6c9371 --- /dev/null +++ b/raw/filings/0001520006/2022/0001520006-23-000056/filing.txt @@ -0,0 +1,3254 @@ +mtdr-20221231 +0001520006 false 2022 FY P5Y P1M http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2022#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2022#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent P3Y P5Y P6Y http://fasb.org/us-gaap/2022#OtherReceivablesNetCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherReceivablesNetCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent 0001520006 2022-01-01 2022-12-31 0001520006 2022-06-30 iso4217:USD 0001520006 2023-02-21 xbrli:shares 0001520006 2022-12-31 0001520006 2021-12-31 iso4217:USD xbrli:shares 0001520006 us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember 2020-01-01 2020-12-31 0001520006 2021-01-01 2021-12-31 0001520006 2020-01-01 2020-12-31 0001520006 us-gaap:CommonStockMember 2019-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2019-12-31 0001520006 us-gaap:RetainedEarningsMember 2019-12-31 0001520006 us-gaap:TreasuryStockMember 2019-12-31 0001520006 us-gaap:ParentMember 2019-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2019-12-31 0001520006 2019-12-31 0001520006 us-gaap:CommonStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-01-01 2020-12-31 0001520006 us-gaap:ParentMember 2020-01-01 2020-12-31 0001520006 us-gaap:TreasuryStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-01-01 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-01-01 2020-12-31 0001520006 us-gaap:CommonStockMember 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-12-31 0001520006 us-gaap:TreasuryStockMember 2020-12-31 0001520006 us-gaap:ParentMember 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-12-31 0001520006 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-01-01 2021-12-31 0001520006 us-gaap:ParentMember 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-01-01 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-01-01 2021-12-31 0001520006 us-gaap:TreasuryStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-12-31 0001520006 us-gaap:TreasuryStockMember 2021-12-31 0001520006 us-gaap:ParentMember 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2022-01-01 2022-12-31 0001520006 us-gaap:ParentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2022-01-01 2022-12-31 0001520006 us-gaap:TreasuryStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2022-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2022-12-31 0001520006 us-gaap:RetainedEarningsMember 2022-12-31 0001520006 us-gaap:TreasuryStockMember 2022-12-31 0001520006 us-gaap:ParentMember 2022-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2022-12-31 0001520006 srt:MinimumMember 2022-01-01 2022-12-31 0001520006 srt:MaximumMember 2022-01-01 2022-12-31 mtdr:purchaser 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember 2022-01-01 2022-12-31 xbrli:pure 0001520006 us-gaap:RevenueFromContractWithCustomerMember us-gaap:CustomerConcentrationRiskMember mtdr:ExxonMobilCorporateMember 2022-01-01 2022-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember 2022-01-01 2022-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember 2022-01-01 2022-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:TwoSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember 2021-01-01 2021-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember us-gaap:CustomerConcentrationRiskMember mtdr:ExxonMobilCorporateMember 2021-01-01 2021-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember 2021-01-01 2021-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember 2021-01-01 2021-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:TwoSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember 2020-01-01 2020-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember 2020-01-01 2020-12-31 0001520006 us-gaap:RevenueFromContractWithCustomerMember us-gaap:CustomerConcentrationRiskMember mtdr:ExxonMobilCorporateMember 2020-01-01 2020-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2022-01-01 2022-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember mtdr:ExxonMobilCorporateMember 2021-01-01 2021-12-31 0001520006 mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2020-01-01 2020-12-31 iso4217:USD utr:bbl iso4217:USD utr:MMBTU 0001520006 us-gaap:MachineryAndEquipmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:MachineryAndEquipmentMember srt:MinimumMember 2022-01-01 2022-12-31 0001520006 srt:MaximumMember us-gaap:MachineryAndEquipmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2020-01-01 2020-12-31 0001520006 srt:OilReservesMember 2022-01-01 2022-12-31 0001520006 srt:OilReservesMember 2021-01-01 2021-12-31 0001520006 srt:OilReservesMember 2020-01-01 2020-12-31 0001520006 srt:NaturalGasReservesMember 2022-01-01 2022-12-31 0001520006 srt:NaturalGasReservesMember 2021-01-01 2021-12-31 0001520006 srt:NaturalGasReservesMember 2020-01-01 2020-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2020-01-01 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2022-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2021-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2022-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2021-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2022-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2021-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2022-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2021-12-31 0001520006 mtdr:CurrentYearMember 2022-12-31 0001520006 mtdr:PriorYearMember 2021-12-31 0001520006 mtdr:TwoYearsPriorMember 2020-12-31 0001520006 mtdr:ThreeYearsPriorMember 2020-12-31 0001520006 mtdr:ThreeYearsandPriorMember 2019-12-31 0001520006 mtdr:ProjectsInceptiontoDateMember 2022-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2022-01-01 2022-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasServiceMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasServiceMember 2021-01-01 2021-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2022-01-01 2022-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2021-01-01 2021-12-31 0001520006 mtdr:DrillingRigLeasesMember 2022-01-01 2022-12-31 0001520006 mtdr:DrillingRigLeasesMember 2021-01-01 2021-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2022-01-01 2022-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2021-01-01 2021-12-31 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2021-12-14 2021-12-14 0001520006 mtdr:PropertiesInLeaAndEddyNMMember srt:MinimumMember 2021-12-14 2021-12-14 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2022-01-01 2022-12-31 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2021-01-01 2021-12-31 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2022-12-31 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2021-12-14 0001520006 mtdr:PropertiesInLeaAndEddyNMMember 2022-09-30 0001520006 mtdr:SummitMidstreamMember 2022-06-30 mtdr:compressorStation utr:mi 0001520006 mtdr:SummitMidstreamMember 2022-06-30 2022-06-30 0001520006 mtdr:SummitMidstreamMember 2022-12-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember mtdr:FivePointMember 2022-12-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2022-12-31 mtdr:well 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-02-17 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember mtdr:FivePointMember 2017-02-17 2021-02-23 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-02-25 2019-02-25 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember mtdr:FivePointMember 2019-02-26 2022-12-31 0001520006 mtdr:FivePointMember 2022-01-01 2022-12-31 0001520006 mtdr:FivePointMember 2021-01-01 2021-12-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember mtdr:RustlerBreaksandWolfAssetAreaMember 2017-02-17 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember mtdr:RustlerBreaksAssetAreaMember 2017-02-17 2017-02-17 0001520006 mtdr:SanMateoMidstreamMember 2022-01-01 2022-12-31 0001520006 mtdr:SanMateoMidstreamMember 2021-01-01 2021-12-31 0001520006 mtdr:SanMateoMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember mtdr:MatadorResourcesCompanyMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember mtdr:FivePointMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember mtdr:FivePointMember 2020-12-31 0001520006 us-gaap:UnsecuredDebtMember us-gaap:SeniorNotesMember 2022-12-31 0001520006 mtdr:CreditAgreementMember us-gaap:LetterOfCreditMember 2022-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SBALoanCARESActMember 2022-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2022-01-01 2022-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2022-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:FourthAmendedCreditAgreementMember 2021-11-18 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:ThirdAmendedCreditAgreementMember 2022-04-29 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:ThirdAmendedCreditAgreementMember 2022-04-30 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2021-12-31 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2022-04-30 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:ThirdAmendedCreditAgreementMember 2022-11-30 0001520006 us-gaap:RevolvingCreditFacilityMember 2022-04-30 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:ThirdAmendedCreditAgreementMember 2020-10-30 0001520006 mtdr:CreditAgreementMember us-gaap:LetterOfCreditMember 2022-01-01 2022-12-31 0001520006 us-gaap:EurodollarMember srt:MinimumMember mtdr:ThirdAmendedCreditAgreementMember 2022-01-01 2022-12-31 0001520006 us-gaap:EurodollarMember srt:MaximumMember mtdr:ThirdAmendedCreditAgreementMember 2022-01-01 2022-12-31 0001520006 mtdr:BaseRateLoanMember srt:MinimumMember 2022-01-01 2022-12-31 0001520006 srt:MaximumMember mtdr:BaseRateLoanMember mtdr:ThirdAmendedCreditAgreementMember 2022-01-01 2022-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2022-04-01 2022-04-30 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MinimumMember 2022-01-01 2022-12-31 0001520006 srt:MaximumMember mtdr:ThirdAmendedCreditAgreementMember 2022-01-01 2022-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2022-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2022-01-01 2022-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2021-06-30 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 0001520006 mtdr:SanMateoCreditFacilityMember 2022-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2021-01-01 2021-02-23 0001520006 us-gaap:FederalFundsEffectiveSwapRateMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember mtdr:AdjustedLIBORateMember 2018-12-19 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember mtdr:AdjustedLIBORateMember srt:MinimumMember 2018-12-19 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember srt:MaximumMember mtdr:AdjustedLIBORateMember 2018-12-19 2018-12-19 0001520006 mtdr:StatutoryReserveRateMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember srt:MinimumMember 2018-12-19 2018-12-19 0001520006 mtdr:StatutoryReserveRateMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember srt:MaximumMember 2018-12-19 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember srt:MinimumMember 2018-12-19 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember srt:MaximumMember 2018-12-19 2018-12-19 0001520006 mtdr:SanMateoCreditFacilityMember mtdr:TheBankOfNovaScotiaMember 2018-12-19 2018-12-19 0001520006 us-gaap:UnsecuredDebtMember mtdr:A2026NotesOfferingMember 2022-12-31 0001520006 us-gaap:DebtInstrumentRedemptionPeriodThreeMember mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2018-10-04 2018-10-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodFourMember 2018-10-04 2018-10-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodFiveMember 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember mtdr:Additional2026NotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2018-10-04 2018-10-04 0001520006 us-gaap:UnsecuredDebtMember mtdr:Additional2026NotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2018-10-04 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2022-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2022-01-01 2022-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2022-12-31 0001520006 us-gaap:EmployeeStockMember 2022-06-30 2022-06-30 0001520006 us-gaap:EmployeeStockMember 2022-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2022-01-01 2022-12-31 0001520006 mtdr:RangeTwoMember 2022-01-01 2022-12-31 0001520006 mtdr:RangeTwoMember 2022-12-31 0001520006 mtdr:RangeFourMember 2022-01-01 2022-12-31 0001520006 mtdr:RangeFourMember 2022-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember srt:MinimumMember 2022-01-01 2022-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember srt:MaximumMember 2022-01-01 2022-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember 2022-01-01 2022-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2022-01-01 2022-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2022-01-01 2022-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2022-01-01 2022-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2022-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember mtdr:RestrictedStockUnitsPerformanceBasedMember 2022-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember srt:MaximumMember mtdr:RestrictedStockUnitsPerformanceBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2021-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2022-01-01 2022-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2021-01-01 2021-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2020-01-01 2020-12-31 0001520006 us-gaap:RestrictedStockMember 2022-12-31 0001520006 us-gaap:RestrictedStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:RestrictedStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:RestrictedStockMember 2020-01-01 2020-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2022-01-01 2022-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2021-01-01 2021-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2020-01-01 2020-12-31 0001520006 2022-02-01 2022-04-30 0001520006 2022-06-01 2022-06-30 0001520006 2022-07-01 2022-12-31 0001520006 2022-12-31 2022-12-31 0001520006 us-gaap:SubsequentEventMember 2023-02-15 2023-02-15 0001520006 2021-01-01 2021-09-30 0001520006 2021-10-01 2021-10-31 0001520006 mtdr:DerivativeContractCalculationPeriodOneMember mtdr:OpenCostlessCollarContractsMember srt:NaturalGasReservesMember 2022-12-31 utr:bbl 0001520006 mtdr:OpenCostlessCollarContractsMember 2022-12-31 0001520006 us-gaap:SubsequentEventMember mtdr:DerivativeContractCalculationPeriodOneMember mtdr:OpenCostlessCollarContractsMember srt:NaturalGasReservesMember 2023-02-21 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2022-01-01 2022-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2022-01-01 2022-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 srt:NaturalGasReservesMember mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 mtdr:RevenuesMember 2022-01-01 2022-12-31 0001520006 mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 mtdr:RevenuesMember 2020-01-01 2020-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel1Member 2022-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel2Member 2022-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2022-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2022-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel1Member 2021-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel2Member 2021-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2021-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2021-12-31 0001520006 us-gaap:PipelinesMember 2022-01-01 2022-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2022-01-01 2022-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2021-01-01 2021-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2022-12-31 0001520006 mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember mtdr:SanMateoMidstreamMember 2022-01-01 2022-12-31 0001520006 mtdr:DrillingRigCommitmentsMember 2022-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2022-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2021-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2022-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2021-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2022-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2021-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2022-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2021-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2022-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2021-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2022-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2021-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2022-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2021-12-31 mtdr:segment 0001520006 us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember mtdr:NaturalGasSalesMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2022-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember us-gaap:NaturalGasMidstreamMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasMidstreamMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember mtdr:NaturalGasSalesMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2021-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OilAndGasMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember us-gaap:NaturalGasMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasMidstreamMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember mtdr:NaturalGasSalesMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2020-01-01 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2020-01-01 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2020-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2020-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2020-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2020-12-31 0001520006 us-gaap:SubsequentEventMember mtdr:AdvanceMember 2023-01-01 2023-01-24 0001520006 us-gaap:SubsequentEventMember mtdr:AdvanceMember 2023-01-24 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31 , 2022 +or +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-35410 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas 27-4662601 +(State or other jurisdiction of +incorporation or organization) (I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 75240 +Dallas, Texas +(Address of principal executive offices) (Zip Code) +( 972 ) 371-5200 +(Registrant’s telephone number, including area code) +_________________________________________________________ +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Trading symbol(s) Name of each exchange on which registered +Common Stock, par value $0.01 per share MTDR New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ☒ No ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ☐ No ☒ +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $ 5,188,536,396 . +As of February 21, 2023, there were 119,071,975 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Auditor Name: KPMG LLP +Auditor Location: Dallas, TX +Auditor Firm ID: 185 +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2022 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +35 +I TEM 1B. +Unresolved Staff Comments +68 +I TEM 2. +Properties +68 +I TEM 3. +Legal Proceedings +68 +I TEM 4. +Mine Safety Disclosures +69 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +70 +I TEM 6. +Selected Financial Data +73 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +73 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +92 +I TEM 8. +Financial Statements and Supplementary Data +93 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +93 +I TEM 9A. +Controls and Procedures +94 +I TEM 9B. +Other Information +96 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +96 +I TEM 11. +Executive Compensation +96 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +96 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +96 +I TEM 14. +Principal Accounting Fees and Services +96 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +97 +ITEM 16. +Form 10-K Summary +97 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; the operating results of and availability of any potential distributions from our joint ventures; weather and environmental conditions; the ongoing impact of the novel coronavirus (“COVID-19”) and its variants on oil and natural gas demand, oil and natural gas prices and our business; our ability to consummate the Advance Acquisition (as defined below) in the anticipated timeframe or at all; risks related to the satisfaction or waiver of the conditions to closing the Advance Acquisition in the anticipated timeframe or at all; risks related to obtaining the requisite regulatory approvals for the Advance Acquisition; disruption from the Advance Acquisition making it more difficult to maintain business and operational relationships; significant transaction costs associated with the Advance Acquisition; the risk of litigation and/or regulatory actions related to the Advance Acquisition; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• our business strategy; +• our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized; +• our cash flows and liquidity; +• the amount, timing and payment of dividends, if any; +• our financial strategy, budget, projections and operating results; +• the supply and demand of oil, natural gas and NGLs; +• oil, natural gas and NGL prices, including our realized prices thereof; +• the timing and amount of future production of oil and natural gas; +• the availability of drilling and production equipment; +• the availability of oil storage capacity; +• the availability of oil field labor; +• the amount, nature and timing of capital expenditures, including future exploration and development costs; +• the availability and terms of capital; +• our drilling of wells; +• our ability to negotiate and consummate acquisition and divestiture opportunities; +• the integration of acquisitions, including the Advance Acquisition, with our business; +• government regulation and taxation of the oil and natural gas industry; +• our marketing of oil and natural gas; +• our exploitation projects or property acquisitions; +• our ability and the ability of our midstream joint venture to construct, maintain and operate midstream pipelines and facilities, including the operation of cryogenic natural gas processing plants and the drilling of additional salt water disposal wells; +• the ability of our midstream business to attract third-party volumes; +• our costs of exploiting and developing our properties and conducting other operations; +• general economic conditions; +1 +Table of Contents +• competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• the effectiveness of our risk management and hedging activities; +• our technology; +• environmental liabilities; +• our initiatives and efforts relating to environmental, social and governance matters; +• counterparty credit risk; +• geopolitical instability and developments in oil-producing and natural gas-producing countries; +• the impact of COVID-19 and its variants on the oil and natural gas industry and our business; +• our future operating results; +• the Advance Acquisition and the anticipated timing and benefits thereof; +• the impact of the Inflation Reduction Act of 2022; and +• our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries and (iv) references to “Pronto” refer to Pronto Midstream, LLC, and the “Pronto Acquisition” refers to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +2 +Table of Contents +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Pronto; +• maintain our financial discipline; +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs and do so in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas prices improved significantly during 2021 and 2022. These factors, along with the successful execution of our business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2022, as well as to increases in our oil and natural gas revenues and cash flows. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down borrowings, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC, our joint venture partner in San Mateo (“Five Point”). Further, we concluded several important financing transactions in 2022, including increasing the borrowing base under our Credit Agreement (as defined below) and extending the maturity of and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved important milestones in 2022, including the addition of produced water disposal capacity and being awarded several new customer contracts. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2022 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2022, we achieved record oil, natural gas and average daily oil equivalent production. In 2022, we produced 21.9 million Bbl of oil, an increase of 23%, as compared to 17.8 million Bbl of oil produced in 2021. We also produced 99.3 Bcf of natural gas, an increase of 22% from 81.7 Bcf of natural gas produced in 2021. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of 22%, as compared to 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, for the year ended December 31, 2021. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2022 and 2021. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, an increase of 10% from 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, at December 31, 2021. The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and PV-10 were primarily a result of the significantly higher unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to +3 +Table of Contents +December 31, 2021. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2022, proved developed reserves included 116.0 million Bbl of oil and 632.9 Bcf of natural gas, and proved undeveloped reserves included 80.3 million Bbl of oil and 329.7 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas reserves at December 31, 2022. Proved developed reserves and proved oil reserves comprised 60% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2021. The improvement in proved developed reserves as a percentage of our total proved oil and natural gas reserves to 62% at December 31, 2022 from 60% at December 31, 2021 was primarily attributable to the development and conversion of approximately 38.4 million BOE of our proved undeveloped reserves to proved developed reserves and the addition of 24.7 million BOE in extensions and discoveries primarily in the Delaware Basin in 2022. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2023. +We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin in 2022, including 81 gross (64.5 net) operated and 63 gross (5.4 net) non-operated wells. At December 31, 2022, our total acreage position in the Delaware Basin was approximately 237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust asset areas in Loving County, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021. We expect our Delaware Basin production to increase in 2023 as we continue the delineation and development of these asset areas. +During 2022, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +• 11 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a staggered fashion in early 2022; these 11 Voni wells have produced in aggregate approximately 3.6 million BOE in 11 months of production; +• the third group of nine Rodney Robinson wells in the western portion of our Antelope Ridge asset area in March 2022; these nine Rodney Robinson wells have produced in aggregate approximately 3.1 million BOE in 10 months of production; +• 11 Rustler Breaks wells in April 2022; these 11 wells have produced in aggregate approximately 2.6 million BOE in almost nine months of production; +• 16 Antelope Ridge wells in the second half of 2022; these 16 wells have produced in aggregate approximately 1.6 million BOE in 2022; and +• 12 Ranger wells in the fourth quarter of 2022. +In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2022 included: +• continued drilling of longer laterals, whereby 90% of the operated horizontal wells we turned to sales in 2022 had lateral lengths of two miles or greater, as compared to 74% in 2020; and +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2022 of $772.5 million, which was at the low end of our revised estimated range for 2022 D/C/E capital expenditures of $765 to $835 +4 +Table of Contents +million as provided on July 26, 2022 and affirmed on October 25, 2022, which included the addition of a seventh operated drilling rig in September 2022. +Capital Resources and Financing Highlights +During 2022, we achieved several significant and important capital resources objectives, which included: +• the generation of free cash flow in all four quarters of 2022; +• the repayment of all outstanding borrowings under our revolving credit facility, resulting in no outstanding borrowings under that facility at December 31, 2022; +• the repurchase of $350.8 million of our outstanding senior notes; +• the amendments of our dividend policy in the second and fourth quarters of 2022, pursuant to which we increased the quarterly cash dividend from $0.05 per share of common stock to $0.15 per share of common stock; and +• the receipt of $28.3 million in performance incentives directly from Five Point. +In addition, we concluded several important financing transactions in 2022 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the spring and fall redetermination processes revised our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.25 billion, as compared to $1.35 billion at December 31, 2021, (ii) increase the elected borrowing commitment to $775.0 million, as compared to $700.0 million at December 31, 2021, (iii) reaffirm the maximum facility amount at $1.5 billion and (iv) add one new bank to our lending group; and +• the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in December 2022 to (i) extend the maturity date by three years from December 2023 to December 2026, (ii) increase the lender commitments under the San Mateo Credit Facility from $450.0 million to $485.0 million, (iii) refresh the accordion feature that provides for potential increases in lender commitments to up to $735.0 million, as compared to $700.0 million previously, and (iv) add one new bank to San Mateo’s lending group. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point, and through Pronto, which is a wholly-owned subsidiary. +San Mateo achieved strong operating results in 2022, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2022 and 2021. +During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. +At December 31, 2022, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the acreage in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); +• Oil Assets : Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +5 +Table of Contents +• Produced Water Assets : 15 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +On June 30, 2022, we acquired a wholly-owned subsidiary of Summit Midstream Partners, LP that was subsequently renamed Pronto, which owned a cryogenic gas processing plant with a designed inlet capacity of 60 MMcf of natural gas per day (the “Marlan Processing Plant”), three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +Environmental, Social and Governance (“ESG”) Initiatives +We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and the highest applicable regulatory and legal standards. More recently, we have begun formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB). +Highlights from our ESG initiatives, which generally relate to our operations in 2021 except as otherwise noted, include: +• Decreased direct greenhouse gas emissions intensity by 28% in 2021, as compared to 2020; +• Decreased methane emissions intensity by 48% in 2021, as compared to 2020; +• Decreased flaring intensity by 53% in 2021, as compared to 2020; +• Increased use of non-fresh water to 96% of total water consumption in 2021; +• Increased number of wells utilizing recycled produced water to 72% of total wells completed in 2021; +• Transported 99% of operated produced water and 89% of operated produced oil by pipeline in 2022; +• Incurred no employee lost time incidents during approximately 3.3 million employee man-hours from 2017 to 2022; and +• Provided approximately 16,000 hours of employee continuing education, equating to approximately 50 hours per employee in 2022. +These sustainability metrics have been calculated using the best information available to us. The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2022 data from our ESG initiatives in the second half of 2023 in connection with the preparation of our 2022 Sustainability Report. +Recent Developments +On January 24, 2023, our wholly-owned subsidiary entered into a definitive agreement to acquire Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped acreage located primarily in Lea County, New Mexico and Ward County, Texas (the “Advance Acquisition”). The consideration for the Advance Acquisition is expected to consist of $1.6 billion in cash, subject to customary closing adjustments, including for working capital and for title and environmental defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the average price of crude oil (as defined in the securities purchase agreement) exceeds $85 per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected to close in the second quarter of 2023 with an effective date of January 1, 2023. +We estimate the total proved oil and natural gas reserves associated with these properties are approximately 106.4 million BOE (73% oil) at December 31, 2022. These reserves estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Other highlights of the Advance Acquisition include: +• Estimated production in the first quarter of 2023 of 24,500 to 25,500 BOE per day (74% oil); +• Approximately 18,500 net acres (99% held by production) in the core of the northern Delaware Basin, most of which is strategically located in our Ranger asset area in Lea County, New Mexico near our existing properties; +• 206 gross (174 net) operated locations (84% working interest) and 200 gross (29 net) non-operated locations (15% working interest); +• 21 gross (20 net) drilled but uncompleted wells expected to be turned to sales in the second half of 2023; +6 +Table of Contents +• Acreage conducive to drilling longer laterals with an expected average lateral length for operated locations of approximately 9,400 feet; and +• Upside related to potential midstream opportunities for Pronto, which operates in Lea County, New Mexico. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2022, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2022. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +237,100 129,400 1,087 543.3 4,382 1,468 346,788 61.0 100,135 +South Texas: +Eagle Ford (5) +15,400 13,100 91 72.3 124 98 3,861 100.0 1,373 +Northwest Louisiana +Haynesville 16,200 8,900 246 19.1 161 14 5,126 99.0 3,789 +Cotton Valley (6) +15,800 14,900 65 39.8 154 35 947 100.0 168 +Area Total (7) +18,500 17,300 311 58.9 315 49 6,073 99.2 3,957 +Total 271,000 159,800 1,489 674.5 4,821 1,615 356,722 62.1 105,465 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2022. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2022, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2022, these engineered drilling locations included 390 gross (156 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon formations, in the Delaware Basin and only seven gross (less than 0.1 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. At December 31, 2022, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2022. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2022, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2022, we also were the operator for approximately 87% of our Eagle Ford acreage and approximately 51% of our Haynesville acreage. +7 +Table of Contents +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2022, our total acreage position in Southeast New Mexico and West Texas was approximately 237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 40,700 gross (22,600 net) acres in our Ranger asset area in Lea County, 59,500 gross (22,500 net) acres in our Arrowhead asset area in Eddy County, 45,500 gross (26,400 net) acres in our Rustler Breaks asset area in Eddy County, 26,500 gross (17,900 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 47,000 gross (25,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2022. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2022, our acreage position in the Delaware Basin was approximately 77% held by existing production. Excluding the Twin Lakes asset area and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 92% held by existing production at December 31, 2022. +During the year ended December 31, 2022, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin, including 81 gross (64.5 net) operated horizontal wells and 63 gross (5.4 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2022, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2022. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021. +8 +Table of Contents +At December 31, 2022, approximately 97% of our estimated total proved oil and natural gas reserves, or 346.8 million BOE, was attributable to the Delaware Basin, including approximately 193.5 million Bbl of oil and 919.7 Bcf of natural gas, an 11% increase, as compared to 312.0 million BOE for the year ended December 31, 2021. Our Delaware Basin proved reserves at December 31, 2022 comprised approximately 99% of our proved oil reserves and 96% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and 95% of our proved natural gas reserves at December 31, 2021. +At December 31, 2022, we had identified 4,382 gross (1,468 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,198 gross (1,296 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2022, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2022, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2022, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2022, these potential future drilling locations included 390 gross (156 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon and Avalon, to which we have assigned proved undeveloped reserves. +We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. +Antelope Ridge Asset Area - Lea County, New Mexico +In the Antelope Ridge asset area, we turned to sales 26 gross (21.9 net) operated wells and 23 gross (0.6 net) non-operated wells during 2022. +The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. At the end of the first quarter of 2022, we achieved one of our five operational milestones we set for Matador in 2022 when we turned to sales nine gross (8.1 net) wells on the Rodney Robinson leasehold. These wells were the third group of wells drilled on the Rodney Robinson leasehold. The nine Rodney Robinson wells, which included one Third Bone Spring completion, two Second Bone Spring completions, three First Bone Spring completions and three Avalon completions, have produced in aggregate approximately 3.1 million BOE in approximately ten months of production. +In the third and fourth quarter of 2022, we achieved another one of our five operational milestones in 2022 when we turned to sales 16 gross (12.9 net) operated wells in other portions of the Antelope Ridge asset area. In addition, we turned to sales one gross (0.9 net) operated well in the first quarter of 2022. In total, these 17 Antelope Ridge wells, which included three Third Bone Spring, eight Second Bone Spring and six First Bone Spring completions have produced in aggregate approximately 1.8 million BOE in an average of approximately four months of production. +In September 2022, we added a seventh drilling rig, which enabled us to accelerate the timing of the fourth group of eight Rodney Robinson wells. These eight gross (7.7 net) wells are expected to be turned to sales late in the first quarter of 2023. We plan to turn to sales 12 gross (9.1 net) operated wells in the Antelope Ridge asset area in 2023. +Rustler Breaks Asset Area - Eddy County, New Mexico +In the Rustler Breaks asset area, we turned to sales 21 gross (13.5 net) operated wells and 22 gross (2.3 net) non-operated wells during 2022. +9 +Table of Contents +In the second quarter of 2022, we achieved one of our five operational milestones in 2022 when we turned to sales eleven gross (6.5 net) wells in the Rustler Breaks asset area. In addition, we turned to sales an additional ten gross (7.0 net) operated wells at various times in the third and fourth quarters of 2022. In total, these 21 Rustler Breaks wells, which included four Wolfcamp B, two Wolfcamp A, two Third Bone Spring, one Third Bone Spring Carbonate, seven Second Bone Spring, four First Bone Spring and one Brushy Canyon completions, have produced in aggregate approximately 3.8 million BOE in an average of approximately six months of production. +We plan to turn to sales 21 gross (13.2 net) operated wells in the Rustler Breaks asset area in 2023. +Arrowhead Asset Area - Eddy County, New Mexico +In the Arrowhead asset area, we turned to sales two gross (1.1 net) operated wells and eight gross (1.3 net) non-operated wells during 2022. This included two Second Bone Spring completions that turned to sales late in the fourth quarter of 2022. +We plan to turn to sales 18 gross (11.5 net) operated wells in the Arrowhead asset area in 2023. +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales 14 gross (10.1 net) operated wells and ten gross (1.2 net) non-operated wells during 2022. In the Twin Lakes area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2022. +In February 2022, we contracted a sixth drilling rig to begin development on certain properties acquired in the western portion of our Ranger asset area and late in the fourth quarter of 2022, we achieved another one of our five operational milestones for 2022 when we turned to sales 12 gross (8.8 net) wells. This included two Wolfcamp A, four Third Bone Spring, five Second Bone Spring and one First Bone Spring completions, which have in aggregate produced 0.3 million BOE in approximately one month of production. +Early in the first quarter of 2022, we also turned to sales the second batch of two Uncle Ches wells, which targeted the Second Bone Spring Sand. We are very pleased with the results of these additional Uncle Ches wells, which in aggregate, have produced over 0.7 million BOE in 11 months of production and are exhibiting high (90%) oil cuts and low water cuts (approximately one Bbl of water per Bbl of oil produced). +We plan to turn to sales 21 gross (14.5 net) operated wells in the Ranger asset area in 2023, not including any wells expected to be turned to sales on Advance’s properties. +Stateline Asset Area - Eddy County, New Mexico +In the Stateline asset area, we turned to sales 15 gross (15.0 net) operated wells during 2022. Early in the first quarter of 2022, we achieved another one of our five operational milestones in 2022 when we turned to sales 11 gross (11.0 net) wells on the Voni leasehold in the Stateline asset area. The 11 Voni wells, which included four Wolfcamp B, five Third Bone Spring Carbonate and two First Bone Spring completions, have produced in aggregate approximately 3.6 million BOE in approximately 11 months of production. These 11 Voni wells had average completed lateral lengths of approximately 12,100 feet. +In the second quarter of 2022, we returned to Stateline to drill an additional batch of four Wolfcamp B wells on the Boros leasehold on the eastern side of the Stateline asset area. These four Wolfcamp B completions were turned to sales late in the third quarter of 2022 and have produced in aggregate approximately 0.5 million BOE in approximately three months. +We plan to turn to sales eight gross (8.0 net) operated wells in the Stateline asset area in 2023. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we turned to sales three gross (2.7 net) operated wells during 2022. This included three Second Bone Spring completions that have in aggregate produced 0.9 million BOE in approximately 11 months. +We plan to turn to sales nine gross (8.3 net) operated wells in the Wolf asset area in 2023 . +South Texas — Eagle Ford Shale and Other Formations +At December 31, 2022, our properties included approximately 15,400 gross (13,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2022. +10 +Table of Contents +During the year ended December 31, 2022, we converted approximately $46.5 million of non-core assets to cash, including the sales of approximately 12,000 gross (12,000 net) acres in the Eagle Ford shale for approximately $46.5 million. We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2022. In fact, as of December 31, 2022, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 35% to 1,373 BOE per day, including 971 Bbl of oil per day and 2.4 MMcf of natural gas per day, during 2022, as compared to 2,126 BOE per day, including 1,528 Bbl of oil per day and 3.6 MMcf of natural gas per day, during 2021. For the year ended December 31, 2022, 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 2% for the year ended December 31, 2021. +At December 31, 2022, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.9 million BOE, was attributable to the Eagle Ford shale, including approximately 2.8 million Bbl of oil and 6.5 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2022, essentially unchanged from December 31, 2021. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated Haynesville shale wells that were turned to sales in 2022. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2023. +At December 31, 2022, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,800 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2022. +For the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or 3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 4% of our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 9% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to these properties. At December 31, 2022, approximately 2% of our estimated total proved reserves, or 6.1 million BOE, was attributable to our properties in Northwest Louisiana. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 21, 2023, we had earned all of the potential $73.5 million in performance incentives. Through February 21, 2023, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021, and the remaining $14.7 million in performance incentives is expected to be paid during the first quarter of 2023. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +11 +Table of Contents +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through mid-2024 , plus additional performance incentives for securing volumes from third-party customers. At February 21, 2023, we had received $62.2 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2022, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +At December 31, 2022, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2022, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area. +In addition, at December 31, 2022, San Mateo had an NGL pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2022, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2022, San Mateo gathered an average of approximately 287 MMcf of natural gas per day, an increase of 22% as compared to 236 MMcf of natural gas per day gathered during the year ended December 31, 2021. In addition, during the year ended December 31, 2022, San Mateo processed approximately 289 MMcf of natural gas at the Black River Processing Plant, an increase of 36%, as compared to 213 MMcf of natural gas per day processed during the year ended December 31, 2021. Natural gas gathering and processing volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain +12 +Table of Contents +San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. +At December 31, 2022, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and (iii) approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +At December 31, 2022, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2022, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. +At December 31, 2022, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2022, the San Mateo Oil Pipeline Systems had throughput of approximately 48,300 Bbl of oil per day, an increase of 18%, as compared to throughput of approximately 40,800 Bbl of oil per day during the year ended December 31, 2021. +Produced Water Gathering and Disposal Assets +During 2022, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 21, 2023, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 21, 2023, San Mateo had designed disposal capacity of approximately 445,000 Bbl of produced water per day. +During the year ended December 31, 2022, San Mateo handled approximately 361,000 Bbl of produced water per day, an increase of 30%, as compared to approximately 278,000 Bbl of produced water per day handled during the year ended December 31, 2021. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo or Pronto. +13 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2022, 2021 and 2020. +Year Ended December 31, +2022 2021 2020 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 21,943 17,840 15,931 +Natural gas (Bcf) 99.3 81.7 69.5 +Total oil equivalent (MBOE) (1) +38,495 31,454 27,514 +Average daily production (BOE/d) (1) +105,465 86,176 75,175 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 96.32 $ 67.58 $ 37.38 +Oil, with realized derivatives (per Bbl) $ 92.87 $ 56.70 $ 39.83 +Natural gas, without realized derivatives (per Mcf) $ 7.98 $ 6.06 $ 2.14 +Natural gas, with realized derivatives (per Mcf) $ 7.15 $ 5.74 $ 2.14 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 7.33 $ 5.69 $ 3.39 +Lease operating $ 4.08 $ 3.46 $ 3.81 +Plant and other midstream services operating $ 2.48 $ 1.95 $ 1.51 +Depletion, depreciation and amortization $ 12.11 $ 10.97 $ 13.15 +General and administrative $ 3.02 $ 3.06 $ 2.27 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 21,585 355 — 3 21,943 +Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3 +Total oil equivalent (MBOE) (3) +36,550 501 1,383 61 38,495 +Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 59,139 971 — 9 60,119 +Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1 +Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465 +Average Sales Prices (4) +Oil (per Bbl) $ 96.34 $ 95.23 $ — $ 91.53 $ 96.32 +Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98 +Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 17,279 558 — 3 17,840 +Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7 +Total oil equivalent (MBOE) (3) +29,395 776 1,217 66 31,454 +Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 47,339 1,528 — 9 48,876 +Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8 +Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176 +Average Sales Prices (4) +Oil (per Bbl) $ 67.65 $ 65.41 $ — $ 64.40 $ 67.58 +Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06 +Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 15,254 674 — 3 15,931 +Natural gas (Bcf) 56.8 1.2 11.0 0.5 69.5 +Total oil equivalent (MBOE) (3) +24,713 883 1,835 83 27,514 +Percentage of total annual net production 89.8 % 3.2 % 6.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 41,678 1,840 — 8 43,526 +Natural gas (MMcf/d) 155.1 3.4 30.1 1.3 189.9 +Total oil equivalent (BOE/d) 67,522 2,412 5,015 226 75,175 +Average Sales Prices (4) +Oil (per Bbl) $ 37.38 $ 37.42 $ 28.77 $ 38.31 $ 37.38 +Natural gas (per Mcf) $ 2.23 $ 2.82 $ 1.66 $ 1.69 $ 2.14 +Total oil equivalent (per BOE) $ 28.19 $ 32.56 $ 9.94 $ 11.09 $ 27.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.52 $ 20.52 $ 4.71 $ 19.39 $ 5.09 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022 increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to 86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was 272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended December 31, 2021. +Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021 increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31, 2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the year ended December 31, 2020. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2022. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 81% in all wells that we operated at December 31, 2022. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +929 461.8 158 81.5 1,087 543.3 +South Texas: +Eagle Ford (2) +91 72.3 — — 91 72.3 +Northwest Louisiana: +Haynesville — — 246 19.1 246 19.1 +Cotton Valley (3) +1 1.0 64 38.8 65 39.8 +Area Total 1 1.0 310 57.9 311 58.9 +Total 1,021 535.1 468 139.4 1,489 674.5 +__________________ +(1) Includes 239 gross (87.5 net) vertical wells that were primarily acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2022, 2021 and 2020. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +At December 31, (1) +2022 2021 2020 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 196,289 181,306 159,949 +Natural Gas (Bcf) 962.6 852.5 662.3 +Total (MBOE) (3) +356,722 323,397 270,332 +Estimated proved developed reserves: +Oil (MBbl) 116,030 102,233 69,647 +Natural Gas (Bcf) 632.9 546.2 323.2 +Total (MBOE) (3) +221,507 193,262 123,507 +Percent developed 62.1 % 59.8 % 45.7 % +Estimated proved undeveloped reserves: +Oil (MBbl) 80,259 79,073 90,301 +Natural gas (Bcf) 329.7 306.4 339.1 +Total (MBOE) (3) +135,215 130,135 146,825 +Standardized Measure (4) (in millions) +$ 6,983.2 $ 4,375.4 $ 1,584.4 +PV-10 (5) (in millions) +$ 9,132.2 $ 5,347.6 $ 1,658.0 +__________________ +17 +Table of Contents +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas, for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas and for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2022, 2021 and 2020 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2022, 2021 and 2020 were $2.15 billion, $972.2 million and $73.6 million, respectively. +Our estimated total proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. This increase in proved oil and natural gas reserves was primarily attributable to (i) our delineation and development operations in the Delaware Basin during 2022 and (ii) the 43% increase in oil prices and the 77% increase in natural gas prices used to estimate total proved reserves at December 31, 2022, as compared to December 31, 2021. We added 71.1 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations turned to sales during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022, but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 7.4 million BOE to proved reserves at a future date. +Our proved oil reserves grew 8% from approximately 181.3 million Bbl at December 31, 2021 to approximately 196.3 million Bbl at December 31, 2022. Our proved natural gas reserves increased 13% from 852.5 Bcf at December 31, 2021 to 962.6 Bcf at December 31, 2022. Our proved reserves to production ratio at December 31, 2022 was 9.3, a decrease of 10% from 10.3 at December 31, 2021. +The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to December 31, 2021. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2022 were $90.15 per Bbl and $6.36 per MMBtu, an increase of 43% and 77%, respectively, as compared to average oil and natural gas prices of $63.04 per Bbl and $3.60 per MMBtu used to estimate proved reserves at December 31, 2021. Our total proved reserves were made up of 55% oil and 45% natural gas at December 31, 2022 and 56% oil and 44% natural gas at December 31, 2021. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +18 +Table of Contents +The following table summarizes changes in our estimated proved developed reserves at December 31, 2022. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2021 193,262 +Extensions and discoveries 24,717 +Net acquisitions of minerals-in-place 753 +Revisions of prior estimates 2,867 +Production (38,495) +Conversion of proved undeveloped to proved developed 38,403 +As of December 31, 2022 221,507 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 15% from 193.3 million BOE at December 31, 2021 to 221.5 million BOE at December 31, 2022. We added 24.7 million BOE in proved developed reserves through extensions and discoveries during 2022, which resulted from new well locations drilled during 2022 to establish proved reserves. We realized approximately 2.9 million BOE in net upward revisions to prior estimates, most of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2022, which resulted in longer estimated economic lives for certain of our producing properties. In addition, we converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022, primarily in our Ranger, Stateline, Antelope Ridge and Rustler Breaks asset areas. In addition, we realized 0.8 million BOE in net upward revisions to our proved developed reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. These cumulative net upward revisions of 66.7 million BOE to our proved developed reserves exceeded by 1.7 times our total oil and natural gas production of 38.5 million BOE in 2022. +Our proved developed oil reserves increased 13% from 102.2 million Bbl at December 31, 2021 to 116.0 million Bbl at December 31, 2022. Our proved developed natural gas reserves increased 16% from 546.2 Bcf at December 31, 2021 to 632.9 Bcf at December 31, 2022. Proved developed reserves constituted 62% of our total proved oil and natural gas reserves at December 31, 2022, as compared to 60% at December 31, 2021. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2022. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2021 130,135 +Extensions and discoveries 46,388 +Net acquisitions of minerals-in-place 264 +Revisions of prior estimates (3,169) +Conversion of proved undeveloped to proved developed (38,403) +As of December 31, 2022 135,215 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increased 4% from 130.1 million BOE at December 31, 2021 to 135.2 million at December 31, 2022. We added 53.8 million BOE in proved undeveloped reserves through extensions and discoveries during 2022, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022 but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. We realized approximately 3.2 million BOE in net downward revisions to our prior estimates of proved undeveloped reserves, most of which was attributable to forecast updates at December 31, 2022. In addition, we realized 0.3 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. During 2022, we also converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022. +19 +Table of Contents +At December 31, 2022, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2022 within five years of booking these reserves. The following table sets forth, since 2019, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2019 13,832 58.8 23,629 $ 318,609 +2020 16,256 76.1 28,944 257,590 +2021 23,965 96.6 40,071 240,664 +2022 22,515 95.3 38,403 434,336 +Total 76,568 326.8 131,047 $ 1,251,199 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2022. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 193,500 919.7 346,788 $ 6,852.8 $ 8,961.8 +South Texas: +Eagle Ford (5) +2,780 6.5 3,861 68.4 89.8 +Northwest Louisiana +Haynesville — 30.8 5,126 56.5 73.9 +Cotton Valley (6) +10 5.6 947 5.2 6.8 +Area Total 10 36.4 6,073 61.7 80.7 +Total 196,290 962.6 356,722 $ 6,982.9 $ 9,132.3 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2022 were approximately $2.15 billion. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual +20 +Table of Contents +production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2022. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2022. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 191,300 99,200 45,800 30,200 237,100 129,400 +South Texas: +Eagle Ford 15,400 13,100 — — 15,400 13,100 +Northwest Louisiana: +Haynesville 16,200 8,900 — — 16,200 8,900 +Cotton Valley 15,800 14,900 — — 15,800 14,900 +Area Total (1) +18,500 17,300 — — 18,500 17,300 +Total 225,200 129,600 45,800 30,200 271,000 159,800 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +21 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2022 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2028 and beyond totals 7,100 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2022. +Acres Acres Acres Acres Acres +Expiring 2023 Expiring 2024 Expiring 2025 Expiring 2026 Expiring 2027 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +7,000 4,300 5,300 1,800 8,600 3,700 5,900 2,000 11,600 11,300 +Total 7,000 4,300 5,300 1,800 8,600 3,700 5,900 2,000 11,600 11,300 +__________________ +(1) Approximately 75% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2022, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2022, approximately 1% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2022, 2021 and 2020 . +Year Ended December 31, +2022 2021 2020 +Gross Net Gross Net Gross Net +Development Wells +Productive 138 61.4 96 40.2 89 44.5 +Dry — — — — — — +Exploration Wells +Productive (1) +20 11.0 8 8.0 4 3.3 +Dry — — — — — — +Total Wells +Productive 158 72.4 104 48.2 93 47.8 +Dry — — — — — — +(1) Includes 17 gross (9.4 net) horizontal and three gross (1.6 net) vertical wells. +At December 31, 2022, we had a total of 25 gross (19.4 net) development wells and nine gross (7.8 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and +22 +Table of Contents +natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids, or NGLs, based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include, but are not limited to: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflict between Russia and Ukraine; domestic or global health concerns, including the outbreak of contagious or pandemic diseases such as COVID-19; the continued threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2022, 2021 and 2020, we had three, three and two significant purchasers, respectively, that accounted for approximately 70%, 72% and 65%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to +23 +Table of Contents +expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals. Although some of these restrictions have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +24 +Table of Contents +Environmental +Emissions Mitigation +We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines with expected sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities. +Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control And Data Acquisition (“SCADA”) equipment at a number of larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require. +Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions. +Water Management +Using improving technologies, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. This use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water. +Land Stewardship +We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, which results in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations. +During 2022, 89% of our gross operated oil production and 99% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil, natural gas and water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the produced oil and water. This is significant because it both (i) reduces truck traffic and increases road safety and (ii) reduces emissions. +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +25 +Table of Contents +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states, including Texas, in August 2022. +In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits is uncertain. +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the EPA suggested increasing the value of the social cost of carbon from $51 per metric ton to $190 per metric ton. +In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. +Although some of the restrictions in the Biden Administration Federal Lease Orders lapsed at the end of 2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is +26 +Table of Contents +located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate +27 +Table of Contents +oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The final 2019 gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +28 +Table of Contents +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures to protect the environment and work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On December 30, 2022, the +29 +Table of Contents +EPA and the Corps jointly issued a pre-publication of a final rule revising the definition of WOTUS that largely returns to the pre-2015 regulatory regime. The rule will become effective 60 days after publication in the Federal Register. +Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the USFWS under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance of NWPs in 2021. In 2021, the Corps issued a new set of NWPs to replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but elected not to consult with the USFWS. The re-issued NWPs were subject to the same legal challenges based on the lack of a formal ESA consultation, but in September 2022, the U.S. District Court for Montana dismissed the ESA-consultation challenges as moot and dismissed the remainder of the lawsuit without prejudice. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and imposes a fee on greenhouse gas (“GHG”) emissions from certain facilities that exceed specified emissions levels. In addition, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on GHGs from new and existing sources in the oil and natural gas industry. On December 6, 2022, the EPA published a supplemental proposal to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA. On December 23, 2022, the EPA proposed a rule that would enable states to implement more stringent methane emissions standards than the federal guidelines require. Also in November 2022, the BLM proposed a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas +30 +Table of Contents +production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. +In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort is designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent +31 +Table of Contents +seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On November 25, 2022, a final rule was published that lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. The effective date of the final rule is March 27, 2023. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle +32 +Table of Contents +Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +As of December 31, 2022, approximately 31% of our Delaware Basin acreage position consisted of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have a material adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +33 +Table of Contents +Human Capital +At December 31, 2022, we had 360 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2022, for example, our employees completed approximately 16,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2022, we estimate our employees have worked approximately 3.3 million combined hours without experiencing a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations to proactively minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +34 +Table of Contents +Item 1A. Risk Factors. +Summary of Risk Factors +The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition, results of operations and cash flows. You should read this summary together with the more detailed risk factors contained below. +Risks Related to the Pending Advance Acquisition +• There can be no assurance as to when or if the Advance Acquisition will be completed. +• We may be unable to successfully integrate Advance’s business or achieve anticipated benefits. +Risks Related to our Financial Condition +• Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. +• Our industry and the broader U.S. economy experienced higher than expected inflationary pressures in 2022. +• We face numerous risks related to the COVID-19 pandemic, including its impact on global oil demand. +• We cannot predict the impact of the ongoing military conflict between Russia and Ukraine. +• Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. +• Our oil and natural gas reserves are estimated , and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +• The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +• Approximately 38% of our total proved reserves at December 31, 2022 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +• Unless we replace our oil and natural gas reserves, our reserves and production will decline. +• We may be required to write down the carrying value of our proved properties under accounting rules. +• Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +• Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. +• Our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth. +• We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. +• We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +• Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +Risks Related to our Liquidity +• We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. +• The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +• The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations. +• Our credit rating may be downgraded, which could reduce our financial flexibility. +• Dividend payments are at the discretion of our Board of Directors and subject to numerous factors. +Risks Related to our Operations +• Drilling for and producing oil and natural gas involve a high degree of operational and financial risk. +• Our reserves and production are concentrated in a few core areas. +• There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. +• Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. +• Multi-well pad drilling may result in volatility in our operating results. +• The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. +• We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. +• Regulatory changes could prevent our ability to continue to pool wells in accordance with our past practices. +35 +Table of Contents +• Midstream projects are subject to risks of construction delays and cost over-runs. +• Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. +• The seismic data and other technologies we use cannot eliminate exploration risk. +Risks Related to Third Parties +• Financial difficulties encountered by purchasers, operators or other third parties could decrease our cash flows from operations. +• The marketability of our production is dependent upon gathering, processing and transportation facilities. +• We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. +• San Mateo’s and Pronto’s long-term success depends on their ability to obtain new sources of products, which depends on certain factors beyond their control. +• Certain of our long-term contracts require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and may limit our ability to use other service providers. +• We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +• Competition in our industry is intense, and our competitors may use superior technology and data resources. +• Strategic relationships upon which we may rely are subject to change. +• We have limited control over activities on properties we do not operate. +Risks Related to Laws and Regulations +• Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations. +• We are subject to government regulation, including complex environmental laws, which could require significant expenditures. +• We are subject to tax laws, and changes thereto could eliminate or reduce certain federal income tax deductions currently available. +• Legislation and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs and additional operating restrictions or delays, and the physical effects of climate change could disrupt our production and cause us to incur significant costs. +• New climate disclosure rules proposed by the SEC could increase our costs of compliance. +• We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +• A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets. +• The rates of our regulated assets are subject to review and reporting by federal regulators. +• Should we fail to comply with FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +• Derivatives legislation adopted by Congress could limit our ability to hedge risks associated with our business. +Risks Relating to Our Common Stock +• The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +• Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect us. +• Future sales and offerings of our common stock could depress the price of our common stock. +• Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. +• The issuance of preferred stock could diminish the rights of holders of our common stock. +General Risk Factors +• We may have difficulty managing growth in our business. +• The loss of any key personnel, Board member or special Board advisor could disrupt our business operations. +• A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +• Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. +• We operate in a litigious environment and may be involved in legal proceedings. +Risks Related to the Pending Advance Acquisition +The consummation of the Advance Acquisition is subject to a number of conditions that may not be satisfied or completed on a timely basis or at all. Accordingly, there can be no assurance as to when or if the Advance Acquisition will be completed, and the failure to complete the Advance Acquisition could have a material and adverse effect on our business, financial condition, results of operations and cash flows. +Although we expect to complete the Advance Acquisition in the second quarter of 2023, there can be no assurances as to the exact timing of the closing or that the Advance Acquisition will be completed at all. The consummation of the Advance +36 +Table of Contents +Acquisition is subject to the satisfaction or waiver of a number of conditions contained in the related securities purchase agreement, including, among others, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the Advance Acquisition uncertain. In addition, the securities purchase agreement contains certain termination rights for both parties, which if exercised will also result in the Advance Acquisition not being consummated. Any such termination or any failure to otherwise complete the Advance Acquisition could result in various consequences, including, among others: our business being adversely impacted by the failure to pursue other beneficial opportunities due to the time and resources committed by our management to the Advance Acquisition, without realizing any of the benefits of completing the Advance Acquisition; being required to pay our legal, accounting and other expenses relating to the Advance Acquisition; the market price of our common stock being adversely impacted to the extent that the current market price reflects a market assumption that the Advance Acquisition will be completed; and negative reactions from the financial markets and customers that may occur if the anticipated benefits of the Advance Acquisition are not realized. Such consequences could materially and adversely affect our business, financial condition, results of operations and cash flows. +Even if the Advance Acquisition is completed, we may be unable to successfully integrate Advance’s business into our business or achieve the anticipated benefits of the Advance Acquisition. +The success of the Advance Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the assets and operations of Advance into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Advance Acquisition. Difficulties in integrating Advance into our company and our ability to manage the combined company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others: +• the inability to successfully integrate Advance operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from the Advance Acquisition; +• not realizing anticipated operating synergies; and +• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Advance Acquisition. +Risks Related to our Financial Condition +Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations. +The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2022, oil prices averaged $94.33 per Bbl, as compared to $68.11 per Bbl in 2021, ranging from a high of $123.70 per Bbl in early March to a low of $71.02 per Bbl in early December, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2022, natural gas prices averaged $6.54 per MMBtu, as compared to $3.71 per MMbtu in 2021, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2022, natural gas prices ranged from a low of $3.72 per MMBtu in early January to a high of $9.68 per MMBtu in mid-August before finishing the year at $4.48 per MMBtu. +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; +• the actions of OPEC+ and state-controlled oil companies; +• the prices and availability of competitors’ supplies of oil, natural gas and NGLs; +• the price and quantity of foreign imports; +• the impact of U.S. dollar exchange rates; +• domestic and foreign governmental regulations and taxes; +• speculative trading of oil and natural gas futures contracts; +37 +Table of Contents +• the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; +• the availability of refining capacity; +• the prices and availability of alternative fuel sources; +• weather conditions and natural disasters, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin; +• political conditions in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; +• the ongoing military conflict between Russia and Ukraine; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19 and its variants; +• the continued threat of terrorism and the impact of military action and civil unrest; +• public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing activities; +• the level of global oil, natural gas and NGL inventories and exploration and production activity; +• the impact of energy conservation efforts; +• technological advances affecting energy consumption; and +• overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relation to each other. +Declines in oil, natural gas or NGL prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. Should oil, natural gas or NGL prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our industry and the broader U.S. economy experienced higher than expected inflationary pressures in 2022 related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. +Inflation in the U.S. has become much more significant in recent years, and in 2022 it reached its highest levels in approximately 40 years. Throughout 2022, we began to experience significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others, as a result of the recent increases in oil and natural gas prices, as well as availability constraints, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, inflation and other factors. These challenges are due in part to increased demand for oil and natural gas production driven by the continued economic recovery from the COVID-19 pandemic and, more broadly, systemic underinvestment in global oil and natural gas development. These supply and demand fundamentals have been further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflict between Russia and Ukraine. We expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Should oil and natural gas prices remain at their current levels or increase, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughout the U.S. and global economy and in the oil and natural gas industry may limit our ability to procure the necessary +38 +Table of Contents +products and services we need for drilling, completing and producing wells in a timely fashion, which could result in delays to our operations and could, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flows. +We face numerous risks related to the COVID-19 pandemic, including its impact on global oil demand, which has had and, depending on the progression of the pandemic, may continue to have, a material adverse effect on our business, financial condition, results of operations and cash flows. +Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 and its variants has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which materially reduced global demand for crude oil, natural gas and NGLs in 2020. Although demand for crude oil, natural gas and NGLs generally increased in 2021 and 2022 as many travel restrictions, business closures and other restrictions on conducting business were lifted in response to improved treatments and availability of vaccinations, we cannot reasonably predict the future impact of COVID-19 or its variants on overall economic activity and the demand for, and pricing of, our products. +The extent to which COVID-19 or its variants will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted, including the duration or any recurrence of the pandemic and responsive measures, the emergence, contagiousness and threat of new strains of the virus and their severity, additional or modified government actions, new information that may emerge concerning the severity of COVID-19 or its variants, the effectiveness of treatments, vaccines and other actions taken to contain COVID-19 or its variants or treat its impact now or in the future, disruptions in the supply chain and an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic, among others. +Some impacts of the COVID-19 pandemic that could have a material adverse effect on our business, financial condition, results of operations and cash flows include: +• significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production; +• decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result, in part, of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19 or its variants; +• increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces; +• significant decreases in the volumes of oil, natural gas and produced water that are transported, gathered, processed or disposed of by San Mateo or Pronto due to curtailed or shut-in production by Matador or other of San Mateo’s or Pronto’s customers; +• increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate; +• increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints; +• the potential for the operations of the Black River Processing Plant, the Marlan Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 or its variants among the relevant workforce; +• the potential for forced curtailment of oil and natural gas production by state governmental agencies, resulting in a need to significantly curtail or shut in our production; +• the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing; +• increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage or the failure of certain of our counterparties to continue as going concerns; +39 +Table of Contents +• increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions; +• the potential impact for delays in construction or increased costs related to midstream construction projects; +• increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and +• increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations. +The COVID-19 pandemic continues to evolve, and the extent to which the pandemic may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired. +We cannot predict the impact of the ongoing military conflict between Russia and Ukraine and the related humanitarian crisis on the global economy, energy markets, geopolitical stability and our business. +On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and sustained conflict and disruption in the region is likely. Although our leasehold acreage is located primarily in the Delaware Basin, the broader consequences of the Russian-Ukrainian conflict, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of the conflict’s effect on our business and results of operations as well as on the global economy and energy markets. +Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• our estimated proved oil and natural gas reserves; +• the amount of oil and natural gas we produce; +• the prices at which we sell our production; +• the costs of developing and producing our oil and natural gas reserves; +• the costs of constructing, operating and maintaining our midstream facilities; +• our ability to attract third-party customers for our midstream services; +• our ability to acquire, locate and produce new reserves; +• the ability and willingness of banks to lend to us; and +• our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak of contagious or pandemic diseases, financial market disruptions, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +40 +Table of Contents +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. +Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• the quality and quantity of available data; +• the interpretation of that data; +• the judgment of the persons preparing the estimate; and +• the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of certain of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• actual prices we receive for oil and natural gas; +• actual costs and timing of development and production expenditures; +• the amount and timing of actual production; and +• changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +41 +Table of Contents +Approximately 38% of our total proved reserves at December 31, 2022 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +At December 31, 2022, approximately 38% of our total proved reserves were undeveloped and less than 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have: +• downward adjustments to our estimated proved reserves; +• increases in our estimates of development costs; or +• deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the +42 +Table of Contents +call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2022. +A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows. +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. +Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in 2020 and 2021, these price differentials for natural gas widened in 2022 and could widen further in future periods. Should we experience future periods of negative pricing for natural gas as we did at certain times in 2020, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. +A component of our growth may come through acquisitions, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets +43 +Table of Contents +or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations. +Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We may not perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. Even when problems with a property or asset are identified, the seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other risks and liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost. +It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may delay or prevent us from utilizing the associated leasehold right or mineral interest, which may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +44 +Table of Contents +Risks Related to our Liquidity +We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs. +As of February 21, 2023, the maximum facility amount under the Credit Agreement was $1.50 billion, the borrowing base was $2.25 billion and our elected borrowing commitment was $775.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). At February 21, 2023, we had available borrowing capacity of approximately $729.4 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of unrestricted cash and cash equivalents), divided by a rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is defined as (x) consolidated current assets plus the unused availability under the Credit Agreement divided by (y) consolidated current liabilities less current maturities under the Credit Agreement, of equal to or greater than 1.0. +As of February 21, 2023, the facility amount under the San Mateo Credit Facility was $485.0 million, and San Mateo had available borrowing capacity of approximately $11.0 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $735.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. In addition to these restrictions, the San Mateo Credit Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. +45 +Table of Contents +In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• increasing our vulnerability to general adverse economic and industry conditions; +• placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• increasing the risk that we may default on our debt obligations. +The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 21, 2023, our borrowing base was $2.25 billion, our elected borrowing commitment was $775.0 million, the maximum facility amount under the Credit Agreement was $1.50 billion and we had no outstanding borrowings under, and approximately $45.6 million in outstanding letters of credit issued pursuant to, the Credit Agreement. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenant noted above). We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a loan based on the secured overnight financing rate administered by the Federal Reserve Bank of New York (“SOFR”). If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for a one month tenor, plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% per annum depending on the level of borrowings under the Credit Agreement. If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.25% to 2.25% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.25% to 3.25% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +Interest rates rose significantly during 2022 as the Federal Reserve sought to control inflation, and interest rates are likely to rise higher during 2023. Our Credit Agreement and the San Mateo Credit Facility have floating rates tied to SOFR or other +46 +Table of Contents +interest rate benchmarks that generally rise alongside the increase in the federal funds rates. As a result, interest expense on our existing floating rate debt rose during 2022 and will likely rise during 2023. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. +The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions. +Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• incur or guarantee additional debt or issue certain types of preferred stock; +• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• transfer or sell assets; +• make certain investments; +• create certain liens; +• enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us; +• consolidate, merge or transfer all or substantially all of our assets; +• engage in transactions with affiliates; and +• create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is defined as current assets plus the unused availability under the Credit Agreement, divided by current liabilities, of equal to or greater than 1.0. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. +Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is defined as consolidated total funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations. +In March 2020, our corporate credit rating from S&P Global Ratings was downgraded from “B+” to “B-” and our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades resulted in significant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services subsequently upgraded our corporate credit rating to “B2” in July 2020, to “B1” in September 2021 and to “Ba3” in September 2022. S&P Global Ratings upgraded our corporate credit rating to “B” in June 2021, “B+” in January 2022 and “BB-” in September 2022. In September 2021, Fitch Ratings assigned us a corporate credit rating of “B+” and subsequently upgraded our corporate credit rating to “BB-” in September 2022. As of February 21, 2023, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “BB-,” “Ba3” and “BB-,” respectively. We cannot assure you that our credit ratings will +47 +Table of Contents +remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +In February 2022 and April 2022, our Board of Directors declared quarterly cash dividends of $0.05 per share of common stock. In June 2022, the Board amended our dividend policy to increase the quarterly dividend to $0.10 per share of common stock. In July 2022 and October 2022, the Board declared quarterly cash dividends of $0.10 per share of common stock. In December 2022, the Board amended our dividend policy to increase the quarterly dividend to $0.15 per share of common stock for future dividend payments. On February 15, 2023, the Board declared a quarterly cash dividend of $0.15 per share of common stock payable on March 9, 2023 to shareholders of record as of February 27, 2023. We intend to continue to pay a quarterly dividend in the future pursuant to the dividend policy adopted by our Board of Directors. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available. +We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price. +Risks Related to our Operations +Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• general economic and industry conditions, including the prices received for oil and natural gas; +• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +48 +Table of Contents +• potential drainage of oil and natural gas from our properties by operations on adjacent properties; +• the existence or magnitude of faults or unanticipated geological features; +• loss of or damage to oilfield development and service tools; +• accidents, equipment failures or mechanical problems; +• title defects of the underlying properties; +• increases in severance taxes; +• adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• domestic and foreign governmental regulations; and +• proximity to and capacity of gathering, processing, transportation and disposal facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +• landing our wellbore in the desired drilling zone; +• staying in the desired drilling zone while drilling horizontally through the formation; +• running our casing the entire length of the wellbore; +• fracture stimulating the planned number of stages; +• drilling out the plugs between stages following hydraulic fracturing operations; and +• being able to run tools and other equipment consistently through the horizontal wellbore. +Each of these risks is magnified in wells with longer laterals. In 2022, 98% of the operated wells we turned to sales had lateral lengths of greater than one mile. In 2023, we anticipate that 96% of the operated wells we turn to sales should have lateral lengths of greater than one mile. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• natural disasters; +• adverse weather conditions; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19 and its variants; +• loss of drilling fluid circulation; +• blowouts where oil or natural gas flows uncontrolled at a wellhead; +• cratering or collapse of the formation; +• pipe or cement leaks, failures or casing collapses; +• damage to pipelines, processing plants and disposal wells and associated facilities; +• fires or explosions; +• releases of hazardous substances or other waste materials that cause environmental damage; +• pressures or irregularities in formations; and +• equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to +49 +Table of Contents +property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. The protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production. In addition, if such a seismic event occurred in the area of San Mateo’s operations, San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. Any such events could adversely impact our and San Mateo’s revenues and cash flows. +There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Marlan Processing Plant and the Black River Processing Plant. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant or the Marlan Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s and Pronto’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s or Pronto’s costs to access and transport on these third-party pipelines significantly increase, their profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo or Pronto gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected. +Insurance against all operational risks is not available to us. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 95% of our total oil and natural gas production for 2022 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2023 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well opportunities in our South Texas and Haynesville shale positions. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel +50 +Table of Contents +or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, including in February 2021 and December 2022, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows. +There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value. +As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows. +Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. +Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. +Multi-well pad drilling may result in volatility in our operating results. +We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, +51 +Table of Contents +including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. +The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. Further, supply chain disruptions being experienced throughout the United States may limit our ability to procure the necessary products and services for drilling and completing wells, which could cause delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could have a material adverse impact on our future production results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +52 +Table of Contents +Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity. +From time-to-time, we, through San Mateo, Pronto or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our drilling locations on federal lands may not be drilled as scheduled. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. +At December 31, 2022, we had leasehold interests in approximately 23,100 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2028. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +53 +Table of Contents +The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Risks Related to Third Parties +Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the years ended December 31, 2022, 2021 and 2020, we had three, three and two significant purchasers, respectively, that collectively accounted for approximately 70%, 72% and 65%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows. +In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate and from San Mateo’s and Pronto’s customers. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. +The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. +54 +Table of Contents +The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2023. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows. +We own and operate substantially all of our midstream assets in Eddy County, New Mexico and Loving County, Texas through San Mateo, and we have and may continue to enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for certain joint ventures and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because of the natural decline in production in the regions of San Mateo’s and Pronto’s midstream operations, San Mateo’s and Pronto’s long-term success depend on their ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s and Pronto’s control. Any decrease in supplies to its midstream facilities could adversely affect San Mateo’s and Pronto’s business and operating results. +San Mateo’s and Pronto’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s and Pronto’s gathering systems and the utilization rate at its other midstream facilities, San Mateo and Pronto must continually obtain new sources of products. San Mateo’s and Pronto’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo and Pronto have no control over the level of activity in the areas of their operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo and Pronto have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2022, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $833.1 million over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of +55 +Table of Contents +these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural gas and to secure trained personnel. Similarly, our midstream business, and particularly the success of San Mateo and Pronto, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo and Pronto compete with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management, Board of Directors and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +56 +Table of Contents +We have limited control over activities on properties we do not operate. +We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• the timing and amount of capital expenditures; +• the operator’s expertise and financial resources; +• the rate of production of reserves, if any; +• approval of other participants in drilling wells; and +• selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +Risks Related to Laws and Regulations +Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands. +At December 31, 2022, Matador held approximately 129,400 net leasehold and mineral acres in the Delaware Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 39,500 net acres, or about 31%, was on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have a material adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. For example, on August 16, 2022, H.R. 5376, commonly known as the Inflation Reduction Act of 2022 (the “IRA”), was enacted. Pursuant to the IRA, the royalty rate for federal leases issued on or after August 16, 2022 was increased to 16.67 percent. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses +57 +Table of Contents +impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements that may be implemented or litigation regarding the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. A change in the presidential administration, as well as a closely divided Congress, may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for: +• personal injuries; +• property damage; +• containment and clean-up of oil, produced water and other spills; +• venting, flaring or other emissions; +• management and disposal of hazardous materials; +• remediation, clean-up costs and natural resource damages; and +• other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA). +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. For example, on November 25, 2022, a final rule was published that, among other things, will list the lesser prairie-chicken as endangered under the ESA in certain portions of southeastern New Mexico where we operate. The effective date of the final rule is currently set to be March 27, 2023. We participate in candidate conservation agreements for the lesser prairie-chicken, as well as the sand dune lizard and +58 +Table of Contents +the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. The listing of the lesser prairie-chicken as endangered, participation in such candidate conservation agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +Historically, we have generated and carried forward net operating losses (“NOL”) in amounts sufficient to offset substantially all of our taxable income and, thus, have not incurred material federal or state income tax liabilities. As of December 31, 2022, we had utilized all or substantially all of our federal NOL carryovers. As a result, unless additional NOLs are generated, we expect that we will begin to incur material federal and state income tax liabilities. +Additionally, the IRA contains a number of revisions to the Internal Revenue Code, including (i) a 15% corporate minimum income tax for certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending with the corporation’s current tax year, (ii) a 1% excise tax on corporate stock repurchases in tax years beginning after December 31, 2022 and (iii) expanded business tax credits and incentives for the development of clean energy projects and the production of clean energy. The impact of the 15% corporate minimum tax will depend on our results of operations each year and anticipated guidance from the Internal Revenue Service. While we do not expect such minimum tax (or any other tax provision contained in the IRA) to have any immediate material impact, we will continue to evaluate its future impact as further information becomes available. +In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The passage of any legislation or any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands, but these rules never became effective. These rules were rescinded by rule in December 2017. The rescission was challenged, and the challenge remains pending before the Ninth Circuit Court of Appeals. Separately, in 2016, BLM issued the 2016 Waste Prevention Rule to address flaring, venting and leaks from oil and natural gas operations on federal lands. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the August 16, 2022 Inflation Reduction Act contains a suite of provisions addressing onshore and offshore oil and natural gas development under federal leases. Under the authority of the Inflation Reduction Act, on November 30, 2022, BLM proposed new regulations to +59 +Table of Contents +reduce the waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on federal and Indian leases. +Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Recently, bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders, if passed at the local, state or federal level could limit our operations. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. See “Business—Regulation—Environmental, Health and Safety Regulation.” +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on the use of injection wells by us or by third parties whom we may contract with to dispose of produced water. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. Any one or more of these developments may result in operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could adversely impact our business, cash flows and results of operations and could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +60 +Table of Contents +Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended NDCs, which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020 but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting a goal to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of alternative sources of energy. On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and, for the first time ever, imposes a fee on GHG emissions from certain facilities that exceed specified emissions levels. Further, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on methane and GHG emissions from new and existing sources in the oil and natural gas industry. On December 6, 2022, the EPA published a supplemental proposal to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA. On December 23, 2022, the EPA proposed a rule that would enable states to implement more stringent methane emissions standards than the federal guidelines require. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing GHG emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibits flaring in certain circumstances and requires upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. The EPA has begun adopting and implementing a comprehensive suite of regulations to restrict GHG emissions under existing provisions of the CAA and the recent authority of the IRA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Any future exploration and development activities and equipment could also be adversely affected by extreme weather conditions such as hurricanes or freezing temperatures, which may cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. Such extreme weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our +61 +Table of Contents +Operations—If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have a material adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain family foundations and sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders, limiting the issuance of federal drilling permits and other federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +President Biden and the Democratic Party, which now controls the U.S. Senate, have identified climate change as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, promoting energy efficiency or the development and consumption of alternative forms of energy, or prohibiting or restricting oil and natural gas development activities in certain areas, have been and likely will be proposed and/or promulgated during the Biden administration. In addition, the Biden administration has already issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before 2050 is a critical priority, affirmed his administration’s desire to establish the United States as a leader in addressing climate change and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes. +New climate disclosure rules proposed by the SEC could increase our costs of compliance and adversely impact our business. +On March 21, 2022, the SEC released proposed new rules that would require significantly expanded climate-related disclosures in SEC filings, including certain climate-related risks, climate-related metrics and GHG emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements. The proposed rules include certain phase-in compliance dates for disclosure of Scope 1, 2 and 3 GHG emissions. As initially proposed, large accelerated filers such as us would be obligated to disclose Scope 1 and 2 GHG emissions for fiscal year 2023 in the 2024 filing year and disclose Scope 3 GHG emissions for fiscal year 2024 in the 2025 filing year. While we are currently assessing the proposed rule, the final form and substance of the rule is not yet known, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent the rule is finalized as proposed, we could incur significant additional costs relating to the assessment and disclosure of climate-related risks, including costs relating to monitoring, collecting, analyzing and reporting the new metrics and implementing systems and procuring additional internal and external personnel with the requisite skills and expertise to serve those functions. These additional costs or changes in operations could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, +62 +Table of Contents +enhanced climate disclosure requirements could accelerate the trend of certain investors and lenders restricting or seeking more stringent conditions with respect to their investments in carbon-intensive sectors. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient. +New regulations on all emissions from our operations could cause us to incur significant costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, BLM issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules were designed to limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the August 16, 2022 IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under Federal leases. Under the authority of the Inflation Reduction Act, on November 30, 2022, BLM proposed new regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on Federal and Indian leases. If not withdrawn or significantly revised, these proposed rules are expected to result in an increase to our operating costs and changes in our operations. In November 2021, the EPA also proposed new NSPS updates and emission guidelines (the “2021 Proposed Methane Rules”) to reduce methane and other pollutants from the oil and gas industry. The EPA issued a supplemental notice of proposed rulemaking on this topic in December 2022 to update, strengthen and expand the 2021 Proposed Methane Rules that would make the proposed requirements more stringent and include sources not previously regulated under the oil and natural gas source category. The EPA has announced that it plans to finalize these rulemakings in 2023. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations. +We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently finalized rulemaking to expand existing integrity management, reporting and records retention, and safety requirements to certain natural gas transmission lines. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which +63 +Table of Contents +includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. +The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +64 +Table of Contents +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +Risks Relating to Our Common Stock +The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2022, our stock price fluctuated between a high of $73.78 and a low of $37.01. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• declaration of dividends or adjustments to our dividend policy; +• speculation in the press or investment community; +• announcement or consummation of acquisitions, dispositions or joint ventures by us; +• public reaction to our operations or plans, press releases, announcements and filings with the SEC; +• the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; +• the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations, such as the Biden Administration Federal Lease Orders; +• sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19 and its variants; +• the realization of any of the risk factors presented in this Annual Report; +• the recruitment or departure of key personnel; +• commencement of, involvement in or unfavorable resolution of litigation; +• the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• changes in market valuations of companies similar to ours; and +• domestic and international economic, legal and regulatory factors unrelated to our performance. +Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price. +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, sovereign +65 +Table of Contents +wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors have published ESG disclosure standards that companies in which they invest are expected to adopt or follow. Furthermore, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. +Certain other stakeholders have pressured commercial and investment banks and other capital providers to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale plays. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected. +Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. +As of February 21, 2023, our directors and executive officers beneficially owned approximately 5.5% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +General Risk Factors +We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo, Pronto or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, +66 +Table of Contents +could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team, the members of our Board and our special Board advisors, and the loss of any key personnel, Board member or special Board advisor could disrupt our business operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. +It has also been widely reported in the press and elsewhere that businesses have faced a more challenging hiring environment since the onset of the COVID-19 pandemic and the subsequent recovery, which has resulted in increased costs to attract skilled labor, such as higher wages or costs for contractors. We may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected. +A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities, including technologies that are managed by third-party service providers or other providers to our industry on whom we directly or indirectly rely to help us collect, host or process information. We depend on such digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our SCADA systems, control important processes and facilities that are critical to our operations. +While we and our third-party service providers commit resources to the design, implementation and monitoring of our information systems, there is no guarantee that these security measures will provide absolute security. Despite these security measures, we may not be able to anticipate, detect or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launch, and because attackers are increasingly using technologies designed to circumvent controls and avoid detection. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses, damage to our reputation and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. In addition, any failure of our third-party providers’ computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business. +While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our or our third-party providers’ systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ +67 +Table of Contents +confidential or proprietary information, operational disruptions, damage to our reputation or financial loss. Additionally, costs for insurance may also increase as a result of cybersecurity threats, and insurance against losses relating to cyber incidents may become more difficult to obtain. +As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and further enhance our protective systems or to investigate and remediate any vulnerabilities. In addition, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. Any failure by us to comply with any additional regulations could result in significant penalties and liability to us, and we cannot predict the potential impact to our business or the energy industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating from cybersecurity issues. +Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition of the Company or other change in control transaction that our shareholders may consider favorable. These provisions include: +• authorization for our Board of Directors to issue preferred stock without shareholder approval; +• a classified Board of Directors so that not all members of our Board of Directors are elected at one time; +• the prohibition of cumulative voting in the election of directors; and +• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +We operate in a litigious environment and may be involved in legal proceedings that could have a material adverse effect on our results of operations and financial condition. +Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows. +68 +Table of Contents +On November 4, 2019, we received a Notice of Violation and Finding of Violation from the EPA and a Notice of Violation from the NMED alleging violations of the CAA and New Mexico State Implementation Plan at certain of our operated locations in New Mexico. We have provided information to the EPA and the NMED and are engaged in discussions regarding a resolution of the alleged violations. We believe it is remote that the resolution of this matter will have a material adverse impact on our financial condition, results of operations or cash flows. Resolution of the matter may result in monetary sanctions of more than $300,000. +Item 4. Mine Safety Disclosures. +Not applicable. +69 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 21, 2023, we had 119,071,975 shares of common stock outstanding held by approximately 325 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Dividends +In February 2022 and April 2022, our Board of Directors declared quarterly cash dividends of $0.05 per share of common stock. In June 2022, the Board amended our dividend policy to increase the quarterly dividend to $0.10 per share of common stock. In July 2022 and October 2022, the Board declared quarterly cash dividends of $0.10 per share of common stock. In December 2022, the Board amended our dividend policy to increase the quarterly dividend to $0.15 per share of common stock for future dividend payments. On February 15, 2023, the Board declared a quarterly cash dividend of $0.15 per share of common stock payable on March 9, 2023 to shareholders of record as of February 27, 2023. We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2022. +Equity Compensation Plan Information +Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1)(2)(3) +1,357,496 $ 22.92 8,755,116 +Equity compensation plans not approved by security holders — — — +Total 1,357,496 $ 22.92 8,755,116 +__________________ +(1) Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). +(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board of Directors in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report. +(3) The Matador Resources Company 2022 Employee Stock Purchase Plan (the “ESPP”) was adopted by our Board of Directors in April 2022 and approved by our shareholders on June 10, 2022. For a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report. +70 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2017 through December 31, 2022, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +71 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2022, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2022 to October 31, 2022 388 $ 66.04 — — +November 1, 2022 to November 30, 2022 — — — — +December 1, 2022 to December 31, 2022 136 61.46 — — +Total +524 $ 64.85 — — +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +72 +Table of Contents +Item 6. Selected Financial Data. +Not applicable. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the ongoing impact of COVID-19 on oil and natural gas demand, oil and natural gas prices and our business, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +For a comparison of our results of operations for the years ended December 31, 2021 and December 31, 2020, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 28, 2022. +Overview +We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +2022 Operational Highlights +We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2022 of $772.5 million, which was at the low end of our revised estimated range for 2022 D/C/E capital expenditures of $765.0 to $835.0 million as provided on July 26, 2022 and affirmed on October 25, 2022. +During the year ended December 31, 2022, we completed and began producing oil and natural gas from 81 gross (64.5 net) operated and 63 gross (5.4 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated Haynesville shale wells that began producing in 2022. +Substantially all of our 2022 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. +Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of 22%, as compared to 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, for the year ended December 31, 2021. Our average +73 +Table of Contents +daily oil production in 2022 was 60,119 Bbl of oil per day, an increase of 23%, as compared to 48,876 Bbl of oil per day in 2021. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production of 272.1 MMcf per day in 2022, an increase of 22%, as compared to 223.8 MMcf per day in 2021. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for each of the years ended December 31, 2022 and 2021. +For the year ended December 31, 2022, our oil and natural gas revenues were $2.91 billion, an increase of 71% from oil and natural gas revenues of $1.70 billion for the year ended December 31, 2021. Our oil revenues increased 75% to $2.11 billion, as compared to $1.21 billion for the year ended December 31, 2021. The increase in oil revenues resulted from a significantly higher weighted average realized oil price of $96.32 per Bbl in 2022, as compared to $67.58 per Bbl in 2021, as well as the 23% increase in oil production for the year ended December 31, 2022 noted above. Our natural gas revenues increased 60% to $792.1 million, as compared to $494.9 million for the year ended December 31, 2021. The increase in natural gas revenues resulted from an increase in our weighted average realized natural gas price of $7.98 per Mcf in 2022, as compared to $6.06 per Mcf in 2021, as well as the 22% increase in natural gas production for the year ended December 31, 2022 noted above. +We reported net income attributable to Matador shareholders of approximately $1.21 billion, or $10.11 per diluted common share, on a GAAP basis for the year ended December 31, 2022, as compared to a net income of $585.0 million, or $4.91 per diluted common share, for the year ended December 31, 2021. Adjusted EBITDA for the year ended December 31, 2022 was $2.13 billion, as compared to Adjusted EBITDA of $1.05 billion for the year ended December 31, 2021. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data—Non-GAAP Financial Measures.” +At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of $9.13 billion. At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, with a Standardized Measure of $4.38 billion and a PV-10 of $5.35 billion. Our estimated total proved reserves of 356.7 million BOE at December 31, 2022 represented a 10% year-over-year increase, as compared to 323.4 million BOE at December 31, 2021. Our estimated proved oil reserves were 196.3 million Bbl at December 31, 2022, an increase of 8%, as compared to 181.3 million Bbl at December 31, 2021, and our estimated proved natural gas reserves were 962.6 Bcf at December 31, 2022, an increase of 13%, as compared to 852.5 Bcf at December 31, 2021. Proved oil reserves comprised 55% of our total proved reserves at December 31, 2022, as compared to 56% at December 31, 2021. At December 31, 2022, 62% of our total proved reserves were proved developed reserves, as compared to 60% at December 31, 2021. +Our proved oil and natural gas reserves in the Delaware Basin increased 11% to 346.8 million BOE at December 31, 2022, as compared to 312.0 million BOE at December 31, 2021, primarily as a result of our ongoing delineation and development operations there. At December 31, 2022, approximately 97% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 9% to 193.5 million Bbl at December 31, 2022, as compared to 177.1 million Bbl at December 31, 2021, and our proved natural gas reserves in the Delaware Basin increased 14% to 919.7 Bcf, as compared to 809.3 Bcf at December 31, 2021. Proved oil reserves comprised 56% of our Delaware Basin total proved reserves at December 31, 2022, as compared to 57% at December 31, 2021. +At both December 31, 2022 and December 31, 2021, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.” +74 +Table of Contents +2022 Midstream Highlights +On June 30, 2022, our wholly-owned subsidiary acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. We assumed certain takeaway capacity on a FERC-regulated natural gas pipeline. As consideration for the business combination, we paid approximately $77.8 million in cash, subject to certain customary post-closing purchase price adjustments. +San Mateo achieved strong operating results in 2022, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2022 and 2021. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. +During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021. +At December 31, 2022, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 15 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +2023 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2023. We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. We have built significant optionality into our 2023 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2023 estimated capital expenditure budget consists of $1.18 to $1.32 billion for D/C/E capital expenditures, which includes expected D/C/E capital expenditures on acreage acquired in the Advance Acquisition, and $150.0 to $200.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2023 capital expenditures as well as the estimated 2023 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. Substantially all of these 2023 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville shale. Our 2023 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2023, including 96% with anticipated completed lateral lengths of one mile or greater. +75 +Table of Contents +On January 24, 2023, our wholly-owned subsidiary entered into a definitive agreement to acquire Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped acreage primarily located in Lea County, New Mexico and Ward County, Texas. The consideration for the Advance Acquisition is expected to consist of $1.6 billion in cash, subject to customary closing adjustments, including for working capital and title and environmental defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the average price of crude oil (as defined in the securities purchase agreement) exceeds $85 per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected to close early in the second quarter of 2023 with an effective date of January 1, 2023. +At December 31, 2022, we had $505.2 million in cash (excluding restricted cash) and $729.4 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $775.0 million). We intend to fund the Advance Acquisition with a combination of cash on hand, free cash flow prior to closing and borrowings under our Credit Agreement, under which we expect to increase our elected commitment in connection with this transaction. Excluding the Advance Acquisition and any other significant acquisitions, we expect to fund our 2023 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2023, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. +We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana (as we have done in recent years), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2023. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2023 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2023. +76 +Table of Contents +Revenues +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2022 2021 2020 +Operating Data: +Revenues (in thousands): (1) +Oil $ 2,113,606 $ 1,205,608 $ 595,507 +Natural gas 792,132 494,934 148,954 +Total oil and natural gas revenues 2,905,738 1,700,542 744,461 +Third-party midstream services revenues 90,606 75,499 64,932 +Sales of purchased natural gas 200,355 86,034 41,742 +Lease bonus - mineral acreage — — 4,062 +Realized (loss) gain on derivatives (157,483) (220,105) 38,937 +Unrealized gain (loss) on derivatives 18,809 21,011 (32,008) +Total revenues $ 3,058,025 $ 1,662,981 $ 862,126 +Net Production Volumes: (1) +Oil (MBbl) 21,943 17,840 15,931 +Natural gas (Bcf) 99.3 81.7 69.5 +Total oil equivalent (MBOE) (2) +38,495 31,454 27,514 +Average daily production (BOE/d) (2) +105,465 86,176 75,175 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 96.32 $ 67.58 $ 37.38 +Oil, with realized derivatives (per Bbl) $ 92.87 $ 56.70 $ 39.83 +Natural gas, without realized derivatives (per Mcf) $ 7.98 $ 6.06 $ 2.14 +Natural gas, with realized derivatives (per Mcf) $ 7.15 $ 5.74 $ 2.14 +________________ +(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2022 as Compared to Year Ended December 31, 2021 +Oil and natural gas revenues . Our oil and natural gas revenues increased $1.21 billion, or 71%, to $2.91 billion for the year ended December 31, 2022, as compared to $1.70 billion for the year ended December 31, 2021. Our oil revenues increased $908.0 million, or 75%, to $2.11 billion for the year ended December 31, 2022, as compared to $1.21 billion for the year ended December 31, 2021. This increase in oil revenues resulted from a 43% increase in the weighted average oil price realized for the year ended December 31, 2022 to $96.32 per Bbl, as compared to $67.58 per Bbl realized for the year ended December 31, 2021, and the 23% increase in our oil production to 21.9 million Bbl of oil for the year ended December 31, 2022, as compared to 17.8 million Bbl of oil for the year ended December 31, 2021. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $297.2 million, or 60%, to $792.1 million for the year ended December 31, 2022, as compared to $494.9 million for the year ended December 31, 2021. The increase in natural gas revenues was primarily attributable to the 32% increase in the weighted average natural gas price realized for the year ended December 31, 2022 to $7.98 per Mcf, as compared to $6.06 per Mcf realized for the year ended December 31, 2021, and the 22% increase in our natural gas production to 99.3 Bcf for the year ended December 31, 2022, as compared to 81.7 Bcf for the year ended December 31, 2021. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. +Third-party midstream services revenues. Our third-party midstream services revenues increased $15.1 million, or 20%, to $90.6 million for the year ended December 31, 2022, as compared to $75.5 million for the year ended December 31, 2021. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $45.1 million for the year ended December 31, 2022, which includes $4.4 million associated with operating our Pronto midstream assets that were purchased on June 30, 2022 as part of the Pronto Acquisition, as compared to $37.6 million for the year ended December 31, 2021, and (ii) an increase in third-party produced water disposal revenues to $35.6 million for the year ended December 31, 2022, as compared to $27.6 million for the year ended December 31, 2021. +77 +Table of Contents +Sales of purchased natural gas. Our sales of purchased natural gas increased $114.3 million, or 133%, to $200.4 million for the year ended December 31, 2022, as compared to $86.0 million for the year ended December 31, 2021. This increase was primarily the result of the increase in realized natural gas prices and an increase in natural gas volumes sold during the year ended December 31, 2022. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of operations. +Realized (loss) gain on derivatives . Our realized net loss on derivatives was $157.5 million for the year ended December 31, 2022, as compared to a realized net loss of approximately $220.1 million for the year ended December 31, 2021. We realized a net loss of $73.9 million related to our oil costless collar for the year ended December 31, 2022, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $81.7 million related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $1.9 million from our oil basis swap contracts for the year ended December 31, 2022, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized a net loss of $197.5 million related to our oil costless collar and swap contracts for the year ended December 31, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $26.1 million related to our natural gas costless collar contracts for the year ended December 31, 2021, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $3.5 million from our oil basis swap contracts for the year ended December 31, 2021, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized an average loss on our oil derivatives of approximately $3.45 per Bbl of oil produced during the year ended December 31, 2022, as compared to an average loss of $10.88 per Bbl of oil produced during the year ended December 31, 2021. We realized an average gain on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022, as compared to an average loss on our natural gas derivatives of approximately $0.32 per Mcf of natural gas produced during the year ended December 31, 2021. Our total oil volumes hedged represented 42% and 61% of our total oil production for the years ended December 31, 2022 and 2021, respectively. Our total natural gas volumes hedged represented 61% and 62% of our total natural gas production the years ended December 31, 2022 and 2021, respectively. +Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $18.8 million for the year ended December 31, 2022, as compared to an unrealized gain of $21.0 million for the year ended December 31, 2021. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts changed from a net liability of approximately $14.9 million to an asset of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the year ended December 31, 2022. During the year ended December 31, 2021, the aggregate net fair value of our open oil and natural gas derivative and oil basis swap contracts decreased from a net liability of approximately $35.9 million to a net liability of approximately $14.9 million, resulting in an unrealized gain on derivatives of approximately $21.0 million for the year ended December 31, 2021. +78 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2022 2021 2020 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing $ 282,193 $ 178,987 $ 93,338 +Lease operating 157,105 108,964 104,953 +Plant and other midstream services operating 95,522 61,459 41,500 +Purchased natural gas 178,937 77,126 32,734 +Depletion, depreciation and amortization 466,348 344,905 361,831 +Accretion of asset retirement obligations 2,421 2,068 1,948 +Full-cost ceiling impairment — — 684,743 +General and administrative 116,229 96,396 62,578 +Total expenses 1,298,755 869,905 1,383,625 +Operating income (loss) 1,759,270 793,076 (521,499) +Other income (expense): +Net loss on asset sales and inventory impairment (1,311) (331) (2,832) +Interest expense (67,164) (74,687) (76,692) +Other (expense) income (5,121) (2,712) 1,864 +Total other (expense) income (73,596) (77,730) (77,660) +Income (loss) before income taxes 1,685,674 715,346 (599,159) +Income tax provision (benefit) +Current 54,877 — — +Deferred 344,480 74,710 (45,599) +Total income tax provision (benefit) 399,357 74,710 (45,599) +Net income attributable to non-controlling interest in subsidiaries (72,111) (55,668) (39,645) +Net income (loss) attributable to Matador Resources Company shareholders $ 1,214,206 $ 584,968 $ (593,205) +Expenses per BOE: +Production taxes, transportation and processing $ 7.33 $ 5.69 $ 3.39 +Lease operating $ 4.08 $ 3.46 $ 3.81 +Plant and other midstream services operating $ 2.48 $ 1.95 $ 1.51 +Depletion, depreciation and amortization $ 12.11 $ 10.97 $ 13.15 +General and administrative $ 3.02 $ 3.06 $ 2.27 +Year Ended December 31, 2022 as Compared to Year Ended December 31, 2021 +Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $103.2 million, or 58%, to $282.2 million for the year ended December 31, 2022, as compared to $179.0 million for the year ended December 31, 2021. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 29% to $7.33 per BOE for the year ended December 31, 2022, as compared to $5.69 per BOE for the year ended December 31, 2021. These increases were primarily attributable to the $93.0 million increase in our production taxes to $222.9 million for the year ended December 31, 2022, as compared to $129.8 million for the year ended December 31, 2021, resulting from the $1.21 billion increase in oil and natural gas revenues for the year ended December 31, 2022, as compared to the year ended December 31, 2021, and the $10.2 million increase in transportation and processing expenses to $59.3 million for the year ended December 31, 2022, as compared to $49.2 million for the year ended December 31, 2021, primarily resulting from the 22% increase in total oil equivalent production between the respective periods. +Lease operating expenses. Our lease operating expenses increased $48.1 million, or 44%, to $157.1 million for the year ended December 31, 2022, as compared to $109.0 million for the year ended December 31, 2021. On a unit-of-production basis, our lease operating expenses increased 18% to $4.08 per BOE for the year ended December 31, 2022, as compared to $3.46 per BOE for the year ended December 31, 2021. These increases in our lease operating expenses for the year ended December 31, 2022 were primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2022, as compared to the year ended December 31, 2021. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $34.1 million, or 55%, to $95.5 million for the year ended December 31, 2022, as compared to $61.5 million for the year ended +79 +Table of Contents +December 31, 2021. This increase was primarily attributable to increased throughput volumes at San Mateo from Matador and other San Mateo customers, which resulted in (i) increased expenses associated with our commercial produced water disposal operations of $46.5 million for the year ended December 31, 2022, as compared to $30.8 million for the year ended December 31, 2021, (ii) increased expenses associated with our expanded pipeline operations of $28.0 million for the year ended December 31, 2022, as compared to $17.5 million for the year ended December 31, 2021, and (iii) increased expenses associated with operating the Black River Processing Plant of $15.8 million for the year ended December 31, 2022, as compared to $13.1 million for the year ended December 31, 2021. In addition, $5.2 million for the year ended December 31, 2022 was associated with operating our Pronto midstream assets, which were purchased on June 30, 2022 as part of the Pronto Acquisition. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $121.4 million, or 35%, to $466.3 million for the year ended December 31, 2022, as compared to $344.9 million for the year ended December 31, 2021, primarily as a result of the 22% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 10% to $12.11 per BOE for the year ended December 31, 2022, as compared to $10.97 per BOE for the year ended December 31, 2021, primarily as a result of the increase in actual costs and estimated future costs to drill, complete and equip our wells between the two periods. +General and administrative. Our general and administrative expenses increased $19.8 million, or 21%, to $116.2 million for the year ended December 31, 2022, as compared to $96.4 million for the year ended December 31, 2021, primarily due to increased compensation expenses for our existing employees as well as the addition of new employees to support the continued growth in our land, geoscience, drilling, completion, production, midstream and administration functions. While our general and administrative expenses increased 21% on an absolute basis, our general and administrative expenses on a unit-of-production basis decreased 1% to $3.02 per BOE for the year ended December 31, 2022, as compared to $3.06 per BOE for the year ended December 31, 2021, primarily as a result of the 22% increase in our total oil equivalent production between the two periods. +Interest expense. For the year ended December 31, 2022, we incurred total interest expense of approximately $77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. For the year ended December 31, 2021, we incurred total interest expense of approximately $79.5 million. We capitalized $4.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2021 and expensed the remaining $74.7 million to operations. +Total income tax provision (benefit). As a result of the full-cost ceiling impairments recorded during 2020, we recognized a valuation allowance against our federal net deferred tax assets as of September 30, 2020. Due to a variety of factors, including our significant net income during 2021, our federal valuation allowance was reversed in the third quarter of 2021. As a result, we recorded a deferred income tax provision of $74.7 million for the year ended December 31, 2021. Our effective tax rate was 11% for the year ended December 31, 2021, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to reversing the valuation allowance against our U.S. federal net deferred tax assets, differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a total income tax provision of $399.4 million for the year ended December 31, 2022. Our effective tax rate was 25% for the year ended December 31, 2022, which differed from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and state taxes, primarily in New Mexico. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue to be during 2023 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. In January 2023, we announced the Advance Acquisition. We intend to fund the Advance Acquisition with a combination of cash on hand, free cash flow prior to closing and borrowings under our Credit Agreement, under which we expect to increase our elected commitment in connection with this transaction. Excluding the Advance Acquisition and any other significant acquisitions, we expect to fund our 2023 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2023, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. +80 +Table of Contents +At December 31, 2022, we had cash totaling $505.2 million and restricted cash totaling $42.2 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +At December 31, 2022, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) no borrowings outstanding under the Credit Agreement and (iii) approximately $45.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. During the first quarter of 2022, our approximately $7.5 million unsecured U.S. Small Business Administration loan, which was issued through Iberiabank in April 2020 as part of the Paycheck Protection Program, was forgiven in full under the terms of the loan agreement and recorded as a gain on the extinguishment of debt within “Other expense” on the consolidated statement of operations. During the year ended December 31, 2022, we repurchased an aggregate principal amount of $350.8 million of our Notes for $344.3 million. +In April 2022, the lenders under the Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $1.35 billion to $2.00 billion, the borrowing commitment was increased from $700.0 million to $775.0 million and the maximum facility amount remained $1.50 billion. In addition, the terms of the Credit Agreement were amended to increase the sublimit for issuances of letters of credit under the Credit Agreement from $50 million to $100 million and replace the London Interbank Offered Rate (“LIBOR”) interest rate benchmark with an Adjusted Term SOFR (as defined in the Credit Agreement) interest rate benchmark. This April 2022 redetermination constituted the regularly scheduled May 1 redetermination. In November 2022, the lenders completed their review of the our proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $2.00 billion to $2.25 billion. We elected to keep the borrowing commitment at $775.0 million, and the maximum facility amount remained $1.50 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenants noted below). The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2022. +At December 31, 2022, San Mateo had $465.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In December 2022, the lenders under the San Mateo Credit Facility extended the maturity of the facility from December 19, 2023 to December 9, 2026 and increased the lender commitments from $450.0 million to $485.0 million. In addition, the lenders agreed to refresh the San Mateo Credit Facility’s accordion feature, which could expand lender commitments to up to $735.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2022. Between December 31, 2022 and February 21, 2023, we repaid an additional $30.0 million of borrowings outstanding under the San Mateo Credit Facility. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2023. We began 2023 operating seven contracted drilling rigs in the Delaware Basin. Upon the consummation of the Advance Acquisition, which we anticipate to occur in the second quarter of 2023, we expect to operate the drilling rig that Advance was operating during the first quarter of 2023, bringing our total contracted drilling rigs to eight. We expect to operate eight contracted drilling rigs for the remainder of 2023. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2023 estimated capital expenditure budget consists of $1.18 to $1.32 billion for D/C/E capital expenditures, which includes expected D/C/E capital expenditures on acreage acquired in the Advance Acquisition, and $150.0 to $200.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2023 capital expenditures as well as the estimated 2023 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. Substantially all of these 2023 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville shale. Our 2023 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a +81 +Table of Contents +high percentage of longer horizontal wells in 2023, including 96% with anticipated completed lateral lengths of greater than one mile. +We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana (as we have done in recent years), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2023. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2023 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2023. +Our 2023 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2023 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2023 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2022. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +82 +Table of Contents +Our cash flows for the years ended December 31, 2022, 2021 and 2020 are presented below. +Year Ended December 31, +2022 2021 2020 +(In thousands) +Net cash provided by operating activities $ 1,978,739 $ 1,053,355 $ 477,582 +Net cash used in investing activities (1,037,477) (729,265) (775,666) +Net cash (used in) provided by financing activities (480,852) (328,553) 324,339 +Net change in cash $ 460,410 $ (4,463) $ 26,255 +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ 2,127,156 $ 1,051,973 $ 519,277 +__________________ +(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. +Cash Flows Provided by Operating Activities +Net cash provided by operating activities increased by $925.4 million to $1.98 billion for the year ended December 31, 2022, as compared to net cash provided by operating activities of $1.05 billion for the year ended December 31, 2021. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.10 billion for the year ended December 31, 2022 from $1.05 billion for the year ended December 31, 2021. This increase was primarily attributable to significantly higher realized oil and natural gas prices for the year ended December 31, 2022, as compared to the year ended December 31, 2021, as well as the 22% increase in total oil equivalent production during 2022, as compared to 2021. Changes in our operating assets and liabilities between December 31, 2021 and December 31, 2022 resulted in a net decrease of approximately $117.0 million in net cash provided by operating activities for the year ended December 31, 2022, as compared to the year ended December 31, 2021. +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. For example, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods, particularly in 2020. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities increased by $308.2 million to $1.04 billion for the year ended December 31, 2022 from $729.3 million for the year ended December 31, 2021. This increase in net cash used in investing activities was primarily attributable an increase of $340.7 million in D/C/E capital expenditures as compared to the year ended December 31, 2021 and the Pronto Acquisition for $75.8 million. These increases were partially offset by an $83.5 million decrease in acquisitions of oil and natural gas properties and a $42.3 million increase in proceeds from the sale of primarily non-core oil and natural gas assets. Cash used for D/C/E capital expenditures for the year ended December 31, 2022 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin. +Cash Flows (Used in) Provided by Financing Activities +Net cash used in financing activities increased by $152.3 million to $480.9 million for the year ended December 31, 2022, as compared to $328.6 million for the year ended December 31, 2021. The net cash used in financing activities for the year ended December 31, 2022 was primarily attributable to (i) the repurchase of an aggregate principal amount of $350.8 million of the Notes for $344.3 million, (ii) net repayments under our Credit Agreement of $100.0 million, (iii) net borrowings under the San Mateo Credit Facility of $80.0 million, (iv) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $57.7 million and (v) dividends paid of $35.2 million. +See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes. +Guarantor Financial Information +83 +Table of Contents +The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2022, the Guarantor Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a guarantor of the Notes. +The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities. +(in thousands) +Summarized Balance Sheet December 31, 2022 +Assets +Current assets $ 991,280 +Net property and equipment $ 3,491,834 +Other long-term assets $ 73,561 +Liabilities +Current liabilities $ 559,087 +Long-term debt $ 695,245 +Other long-term liabilities $ 496,425 +(in thousands) Year Ended +Summarized Statement of Operations December 31, 2022 +Revenues $ 2,080,396 +Expenses 1,271,359 +Operating income $ 809,037 +Other expense (55,935) +Tax provision (399,357) +Net income $ 353,745 +Non-GAAP Financial Measures +We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +84 +Table of Contents +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. +Year Ended December 31, +2022 2021 2020 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): +Net income (loss) attributable to Matador Resources Company shareholders $ 1,214,206 $ 584,968 $ (593,205) +Net income attributable to non-controlling interest in subsidiaries 72,111 55,668 39,645 +Net income (loss) 1,286,317 640,636 (553,560) +Interest expense 67,164 74,687 76,692 +Total income tax provision (benefit) 399,357 74,710 (45,599) +Depletion, depreciation and amortization 466,348 344,905 361,831 +Accretion of asset retirement obligations 2,421 2,068 1,948 +Full-cost ceiling impairment — — 684,743 +Unrealized (gain) loss on derivatives (18,809) (21,011) 32,008 +Non-cash stock-based compensation expense 15,123 9,039 13,625 +Net loss on asset sales and impairment 1,311 331 2,832 +Expense related to contingent consideration and other 4,926 1,485 — +Consolidated Adjusted EBITDA 2,224,158 1,126,850 574,520 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (97,002) (74,877) (55,243) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 2,127,156 $ 1,051,973 $ 519,277 +Year Ended December 31, +2022 2021 2020 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities: +Net cash provided by operating activities $ 1,978,739 $ 1,053,355 $ 477,582 +Net change in operating assets and liabilities 117,935 982 23,078 +Interest expense, net of non-cash portion 63,064 71,028 73,860 +Current income tax provision 54,877 — — +Expense related to contingent consideration and other 9,543 1,485 — +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (97,002) (74,877) (55,243) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 2,127,156 $ 1,051,973 $ 519,277 +For the year ended December 31, 2022, we reported net income attributable to Matador shareholders of $1.21 billion, as compared to $585.0 million for the year ended December 31, 2021. This increase primarily resulted from significantly higher realized oil and natural gas prices and higher oil and natural gas production, for the year ended December 31, 2022, as compared to the year ended December 31, 2021. These increases were partially offset by an increase in operating expenses, depletion, depreciation and amortization and income tax expense between the two periods. +Adjusted EBITDA, a non-GAAP financial measure, increased $1.08 billion to $2.13 billion for the year ended December 31, 2022, as compared to $1.05 billion for the year ended December 31, 2021. This increase was primarily attributable to the significantly higher realized oil and natural gas prices and higher oil and natural gas production noted above for the year ended December 31, 2022, as compared to the year ended December 31, 2021. These increases were partially offset by an increase in operating expenses between the two periods. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2022, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +85 +Table of Contents +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2022. +Payments Due by Period +Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years +(In thousands) +Contractual Obligations: +Borrowings, including letters of credit (1) +$ 519,572 $ — $ — $ 519,572 $ — +Senior unsecured notes (2) +699,191 — — 699,191 — +Office leases 14,373 4,242 8,671 1,460 — +Non-operated drilling commitments (3) +25,992 25,992 — — — +Drilling rig contracts (4) +17,703 17,703 — — — +Asset retirement obligations (5) +53,741 756 5,199 1,889 45,897 +Transportation, gathering, processing and disposal agreements with non-affiliates (6) +541,085 70,648 142,424 131,083 196,930 +Transportation, gathering, processing and disposal agreements with San Mateo (7) +291,979 1,773 182,740 107,466 — +Midstream compressor contracts (8) +29,833 29,833 — — — +Total contractual cash obligations $ 2,193,469 $ 150,947 $ 339,034 $ 1,460,661 $ 242,827 +__________________ +(1) The amounts included in the table above represent principal maturities only. At December 31, 2022, we had no borrowings outstanding under the Credit Agreement and approximately $45.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 31, 2026. At December 31, 2022 San Mateo had $465.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures December 9, 2026. Assuming the amounts outstanding and interest rate of 6.68% for the San Mateo Credit Facility at December 31, 2022, the interest expense for such facilities is expected to be approximately $31.5 million each year until maturity. +(2) The amounts included in the table above represent principal maturities only. Interest expense on the $699.2 million of Notes that were outstanding as of December 31, 2022 is expected to be approximately $41.1 million each year until maturity. +(3) At December 31, 2022, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. +(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2022. +(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments. +(7) We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(8) At December 31, 2022, we had outstanding commitments to purchase 12 compressors to be utilized in San Mateo and Pronto operations. +86 +Table of Contents +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the ongoing military conflict between Russia and Ukraine as well as political instability in China and the Middle East, the actions of OPEC+, the ongoing impact of COVID-19 and its variants, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. +The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +During the years ended December 31, 2021 and 2022 and through February 21, 2023, the oil and natural gas industry experienced continued improvement in commodity prices, as compared to 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 subsided, (ii) actions taken by OPEC+ to moderate the worldwide supply of oil and (iii) changes in supply and demand dynamics, particularly with respect to the ongoing military conflict between Russia and Ukraine. While oil and natural gas prices improved significantly in 2021, 2022 and early 2023, the general outlook for the oil and natural gas industry for the remainder of 2023 remains unclear, and we can provide no assurances that commodity prices will remain at current levels or increase further. In fact, commodity prices may decline from their current levels, particularly in response to the spread of new variants, if any, of COVID-19, the actions of OPEC+ and other governmental authorities and state-controlled oil companies to increase the global oil supply and milder weather conditions, among other factors. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations” in this Annual Report. The economic disruptions associated with COVID-19 and its variants, the ongoing military conflict between Russia and Ukraine and the volatility in oil and natural gas prices have also impacted our ability to access the capital markets on reasonably similar terms as were available prior to 2020. +For the year ended December 31, 2022, oil prices averaged $94.33 per Bbl, as compared to $68.11 per Bbl in 2021, ranging from a high of $123.70 per Bbl in early March to a low of $71.02 per Bbl in early December, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $96.32 per Bbl ($92.87 per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2022, as compared to $67.58 per Bbl ($56.70 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2021. At February 21, 2023, the WTI oil futures contract price for the earliest delivery date had decreased from year-end 2022, closing at $76.16 per Bbl, and was also lower compared to $91.07 per Bbl on February 18, 2022. +Natural gas prices also increased significantly during 2022. For the year ended December 31, 2022, natural gas prices averaged $6.54 per MMBtu, as compared to $3.71 per MMBtu in 2021, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2022, natural gas prices ranged from a low of $3.72 per MMBtu in early January to a high of $9.68 per MMBtu in mid-August. As a result of milder-than-expected winter weather, natural gas prices declined over the course of the fourth quarter of 2022, finishing the year at $4.48 per MMBtu. We realized a weighted average natural gas price of $7.98 per Mcf ($7.15 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2022, as compared to $6.06 per Mcf ($5.74 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2021. As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average natural gas price. At February 21, 2023, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from year-end 2022, closing at $2.31 per MMBtu, and was also lower as compared to $4.43 per MMBtu at February 18, 2022. +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the +87 +Table of Contents +borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2022, we incurred realized losses on our oil and natural gas derivative contracts of approximately $157.5 million, primarily as a result of oil and natural gas prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts and above the strike price of certain oil basis swap contracts. At December 31, 2022, almost all of the derivative contracts we had in place that contributed to these realized losses on derivatives in 2022 had expired. At February 21, 2023, given current oil and natural gas prices and the oil and natural gas derivative contracts we have in place, we do not anticipate losses of such magnitude from our derivative contracts in 2023, although there may be periods where we realize losses from derivatives. At December 31, 2022, we had natural gas costless collar contracts in place for approximately 2.4 million MMBtu. +The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2022, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas. +The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 21, 2023, this oil price differential was approximately +$2.17 per Bbl. At February 21, 2023, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2023. +Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In early 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin, particularly beginning in the latter half of 2022, began to increase. As a result, the Waha basis differential began to widen, and, at February 21, 2023, this natural gas price differential was approximately ($0.70) per MMBtu. A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2021 and 2022, we typically realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 10% of our reported natural gas production for the year ended December 31, 2022 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. +As of February 21, 2023, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have in previous periods, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, although we have contracted firm physical transports that limit our exposure to the Waha basis differential, we had derivative contracts in place to mitigate our exposure to these natural gas price differentials as of February 21, 2023. +In 2022, we began to experience significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others, as a result of the recent increases in oil and natural gas prices, as well as availability constraints, supply chain disruption, increased demand, labor shortages associated with a fully employed U.S. labor force, inflation and other factors. Should oil and natural gas prices remain at their current levels or increase further, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely fashion, which could result in delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows. +In addition, we utilized substantially all of our federal and state NOL carryforwards in 2022 and became subject to federal and state income taxes, which is reflected in our current income tax provision of $54.9 million for the year ended December 31, 2022. At February 21, 2023, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico for 2023. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry +88 +Table of Contents +increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has implemented similar rules and regulations. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +In January 2021, President Biden signed an executive order instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices, which lapsed at December 31, 2022. In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico. In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making. The BLM indicated that the Lease Sale Litigation or the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. The impact of federal actions and lawsuits related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well. +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, +89 +Table of Contents +sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth”. +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2022. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +90 +Table of Contents +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” +Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Derivative Financial Instruments +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently as an unrealized gain or loss on derivatives in our consolidated statements of operations. Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. +91 +Table of Contents +Stock-Based Compensation +We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock. +We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on the date of the grant for awards issued under the 2012 Incentive Plan and on the trading day prior to the date of grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2022. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2022, PNC Bank was the counterparty for our derivative instrument. We have considered the credit standing of the counterparty in determining the fair value of our derivative financial instruments. +At December 31, 2022, we had entered into a costless collar contract to mitigate our exposure to fluctuations in natural gas prices, with an established price floor and ceiling. When the settlement price is below the price floor established by the collar, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by the costless collar, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. +92 +Table of Contents +See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2022. Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors—Risks Related to Laws and Regulations—The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt. At December 31, 2022, we had no outstanding borrowings under our Credit Agreement, $699.2 million in Notes outstanding at a coupon rate of 5.875% per annum and $465.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 6.68% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo and Pronto are subject to the credit risk of their customers. The inability or failure of our, San Mateo’s or Pronto’s significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparty on our derivative financial instruments in place at February 21, 2023 was PNC Bank, who is also a lender (or affiliate thereof) under our Credit Agreement. +Impact of inflation . Inflation in the United States has become much more significant in recent years, and in 2022 it reached its highest levels in approximately 40 years. At February 21, 2023, we do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward. We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. We have begun to experience such inflationary pressure in our drilling and completion and midstream operations, and we budgeted a 10 to 20% increase in oilfield service costs in preparing our full year 2023 D/C/E and midstream capital expenditures estimates. See “Risk Factors—Risks Related to our Financial Condition—Our industry and the broader U.S. economy experienced higher than expected inflationary pressures in 2022, related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected” and “Risk Factors—Risks Related to our Operations—The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report beginning on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +93 +Table of Contents +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2022 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2022, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2022 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +94 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements), and our report dated March 1, 2023 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +March 1, 2023 +95 +Table of Contents +Item 9B. Other Information. +Not applicable. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2023 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 3—Ratification of Appointment of KPMG LLP.” +96 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2022 and 2021, Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2022, 2021 and 2020 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020. +2. Financial Statement Schedules : All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto. +3. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below. +Item 16. Form 10-K Summary. +None. +97 +Table of Contents +EXHIBIT INDEX +Exhibit +Number Description +2.1* +Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017). +2.2* +Securities Purchase Agreement, dated January 24, 2023, by and among MRC Hat Mesa, LLC, MRC Energy Company (solely for the limited purposes stated therein), AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 24, 2023). +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018). +4.3 +First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018). +4.4 +Second Supplemental Indenture, dated as of December 14, 2021, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N. A., as agent for Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on December 14, 2021). +4.5 +Description of Capital Stock (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2019). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.4† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.5† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.6† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +98 +Table of Contents +10.7† +First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.8† +First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.9† +Form of Employment Agreement between Matador Resources Company and each of Michael D. Frenzel, W. Thomas Elsener and Brian J. Willey (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 20, 2022). +10.10† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.11 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.12 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.13 +Fourth Amended and Restated Credit Agreement, dated as of November 18, 2021, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 18, 2021). +10.14 +First Amendment to Fourth Amended and Restated Credit Agreement dated as of April 25, 2022, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2022). +10.15† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.16† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.17† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.18† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.19† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.20† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.21† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.22† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.23† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +99 +Table of Contents +10.24† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.25† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.26† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.27† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.28† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.29† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.30† +Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019). +10.31† +First Amendment to Matador Resources Company 2019 Long-Term Incentive Plan effective April 21, 1011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 16, 2022). +10.32† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.33† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.34† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.35† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.36† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.58 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.37† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.38† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan with ratable vesting for employees without employment agreements (incorporated by reference to Exhibit 10.60 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.39† +Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the year ended December 31, 2020). +10.40† +Matador Resources Company 2022 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 16, 2022). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +22.1 +List of Subsidiary Guarantors (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +100 +Table of Contents +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2021, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +104 Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101). +† Indicates a management contract or compensatory plan or arrangement. +* This filing excludes certain schedules and exhibits pursuant to Item 601(a)(5) of Regulation S-K, which the Company agrees to furnish supplementally to the SEC upon request; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished. +101 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +March 1, 2023 By: /s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature Title Date +/s/ Joseph Wm. Foran Chairman and Chief Executive Officer March 1, 2023 +Joseph Wm. Foran (Principal Executive Officer) +/s/ Brian J. Willey Chief Financial Officer, President of Midstream Operations and Executive Vice President March 1, 2023 +Brian J. Willey (Principal Financial Officer) +/s/ Robert T. Macalik Executive Vice President and Chief Accounting Officer March 1, 2023 +Robert T. Macalik (Principal Accounting Officer) +/s/ Reynald A. Baribault Director March 1, 2023 +Reynald A. Baribault +/s/ R. Gaines Baty Director March 1, 2023 +R. Gaines Baty +/s/ William M. Byerley Director March 1, 2023 +William M. Byerley +/s/ Monika U. Ehrman Director March 1, 2023 +Monika U. Ehrman +/s/ Julia P. Forrester Rogers Director March 1, 2023 +Julia P. Forrester Rogers +/s/ James M. Howard Director March 1, 2023 +James M. Howard +/s/ Timothy E. Parker Director March 1, 2023 +Timothy E. Parker +/s/ Kenneth L. Stewart Director March 1, 2023 +Kenneth L. Stewart +102 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water. +Bcf . One billion cubic feet of natural gas. +Bench . A geologic zone or formation or a subdivision of a geologic formation. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Central delivery point or CDP . The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differential . The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. +Dry hole . A well found to be incapable of producing hydrocarbons. +ESP . Electric submersible pump. +Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +GAAP, or U.S. GAAP . United States, generally accepted accounting principles. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +103 +Table of Contents +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Lateral length . Length of the drilled or completed portion of a horizontal well. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or produced water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Organization of Petroleum Exporting Countries or OPEC . An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid. +OPEC+ . A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. +Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. +104 +Table of Contents +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Prospectivity . Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Spud . The act of beginning to drill an oil or natural gas well. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +105 +Table of Contents +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserves analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +WTI . West Texas Intermediate. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +106 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2022, 2021 and 2020 +Index +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 202 2 and 202 1 +F-4 +Consolidated Statements of Operations for the Years Ended December 31, 202 2 , 202 1 and 20 20 +F-5 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 202 2 , 202 1 and 20 20 +F-6 +Consolidated Statements of Cash Flows for the Years Ended December 31, 202 2 , 202 1 and 20 20 +F- 7 +Notes to Consolidated Financial Statements +F- 8 +Unaudited Supplementary Information +F- 38 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2022 and 2021, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2023 expressed an opinion on the effectiveness of the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation +As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. For the year ended December 31, 2022, the Company recorded depletion expense of evaluated oil and natural gas +F-2 +Table of Contents +properties of $428.9 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company recorded $6.9 billion of gross evaluated oil and natural gas properties as of December 31, 2022. The Company’s internal reserves engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reserves engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company. +We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reserves engineers as well as the external reserves engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reserves engineers, and (3) the relationship of the external reserves engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reserves engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reserves engineers’ estimate regarding future operating and development costs based on historical actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reserves engineers in connection with our evaluation of the Company’s reserves estimates. We analyzed the depletion expense calculation for compliance with industry and regulatory standards, and recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +March 1, 2023 +F-3 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2022 2021 +ASSETS +Current assets +Cash $ 505,179 $ 48,135 +Restricted cash 42,151 38,785 +Accounts receivable +Oil and natural gas revenues 224,860 164,242 +Joint interest billings 180,947 48,366 +Other 48,011 28,808 +Derivative instruments 3,930 1,971 +Lease and well equipment inventory 15,184 12,188 +Prepaid expenses and other current assets 51,570 28,810 +Total current assets 1,071,832 371,305 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated 6,862,455 6,007,325 +Unproved and unevaluated 977,502 964,714 +Midstream properties 1,057,668 900,979 +Other property and equipment 32,847 30,123 +Less accumulated depletion, depreciation and amortization ( 4,512,275 ) ( 4,046,456 ) +Net property and equipment 4,418,197 3,856,685 +Other assets +Other long-term assets 64,476 34,163 +Total assets $ 5,554,505 $ 4,262,153 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable $ 58,848 $ 26,256 +Accrued liabilities 261,310 253,283 +Royalties payable 117,698 94,359 +Amounts due to affiliates 32,803 27,324 +Derivative instruments — 16,849 +Advances from joint interest owners 52,357 18,074 +Other current liabilities 52,857 28,692 +Total current liabilities 575,873 464,837 +Long-term liabilities +Borrowings under Credit Agreement — 100,000 +Borrowings under San Mateo Credit Facility 465,000 385,000 +Senior unsecured notes payable 695,245 1,042,580 +Asset retirement obligations 52,985 41,689 +Deferred income taxes 428,351 77,938 +Other long-term liabilities 19,960 22,721 +Total long-term liabilities 1,661,541 1,669,928 +Commitments and contingencies (Note 14) +Shareholders’ equity +Common stock — $ 0.01 par value, 160,000,000 shares authorized; 118,953,381 and 117,861,923 shares issued; and 118,948,624 and 117,850,233 shares outstanding, respectively +1,190 1,179 +Additional paid-in capital 2,101,999 2,077,592 +Retained earnings (accumulated deficit) 1,007,642 ( 171,318 ) +Treasury stock, at cost, 4,757 and 11,945 shares, respectively +( 34 ) ( 243 ) +Total Matador Resources Company shareholders’ equity 3,110,797 1,907,210 +Non-controlling interest in subsidiaries 206,294 220,178 +Total shareholders’ equity 3,317,091 2,127,388 +Total liabilities and shareholders’ equity $ 5,554,505 $ 4,262,153 +The accompanying notes are an integral part of these consolidated financial statements. +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +Year Ended December 31, +2022 2021 2020 +Revenues +Oil and natural gas revenues $ 2,905,738 $ 1,700,542 $ 744,461 +Third-party midstream services revenues 90,606 75,499 64,932 +Sales of purchased natural gas 200,355 86,034 41,742 +Lease bonus - mineral acreage — — 4,062 +Realized (loss) gain on derivatives ( 157,483 ) ( 220,105 ) 38,937 +Unrealized gain (loss) on derivatives 18,809 21,011 ( 32,008 ) +Total revenues 3,058,025 1,662,981 862,126 +Expenses +Production taxes, transportation and processing 282,193 178,987 93,338 +Lease operating 157,105 108,964 104,953 +Plant and other midstream services operating 95,522 61,459 41,500 +Purchased natural gas 178,937 77,126 32,734 +Depletion, depreciation and amortization 466,348 344,905 361,831 +Accretion of asset retirement obligations 2,421 2,068 1,948 +Full-cost ceiling impairment — — 684,743 +General and administrative 116,229 96,396 62,578 +Total expenses 1,298,755 869,905 1,383,625 +Operating income (loss) 1,759,270 793,076 ( 521,499 ) +Other income (expense) +Net loss on asset sales and impairment ( 1,311 ) ( 331 ) ( 2,832 ) +Interest expense ( 67,164 ) ( 74,687 ) ( 76,692 ) +Other (expense) income ( 5,121 ) ( 2,712 ) 1,864 +Total other expense ( 73,596 ) ( 77,730 ) ( 77,660 ) +Income (loss) before income taxes 1,685,674 715,346 ( 599,159 ) +Income tax provision (benefit) +Current 54,877 — — +Deferred 344,480 74,710 ( 45,599 ) +Total income tax provision (benefit) 399,357 74,710 ( 45,599 ) +Net income (loss) 1,286,317 640,636 ( 553,560 ) +Net income attributable to non-controlling interest in subsidiaries ( 72,111 ) ( 55,668 ) ( 39,645 ) +Net income (loss) attributable to Matador Resources Company shareholders $ 1,214,206 $ 584,968 $ ( 593,205 ) +Earnings (loss) per common share +Basic $ 10.28 $ 5.00 $ ( 5.11 ) +Diluted $ 10.11 $ 4.91 $ ( 5.11 ) +Weighted average common shares outstanding +Basic 118,122 116,999 116,068 +Diluted 120,131 119,163 116,068 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2022, 2021 and 2020 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital (Accumulated deficit) retained earnings Treasury Stock Non-controlling interest in subsidiaries +Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2020 116,644 $ 1,166 $ 1,981,014 $ ( 148,500 ) 1 $ ( 26 ) $ 1,833,654 $ 135,798 $ 1,969,452 +Issuance of common stock pursuant to employee stock compensation plan 244 2 ( 2 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 85 1 ( 1 ) — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 17,452 — — — 17,452 — 17,452 +Stock options exercised, net of options forfeited in net share settlements — — ( 24 ) — — — ( 24 ) — ( 24 ) +Liability-based stock option awards settled in equity 22 — 297 — — — 297 — 297 +Restricted stock forfeited — — — — 149 ( 1,489 ) ( 1,489 ) — ( 1,489 ) +Contribution related to formation of San Mateo, net of tax of $ 3.1 million (See Note 6) +— — 11,613 — — — 11,613 — 11,613 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $ 4.8 million (See Note 6) +— — 18,232 — — — 18,232 96,622 114,854 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 45,570 ) ( 45,570 ) +Cancellation of treasury stock ( 148 ) — ( 1,512 ) — ( 148 ) 1,512 — — — +Current period net (loss) income — — — ( 593,205 ) — — ( 593,205 ) 39,645 ( 553,560 ) +Balance at December 31, 2020 116,847 1,169 2,027,069 ( 741,705 ) 2 ( 3 ) 1,286,530 226,495 1,513,025 +Dividends declared ( 0.125 per share) +— — — ( 14,581 ) — — ( 14,581 ) — ( 14,581 ) +Issuance of common stock pursuant to employee stock compensation plan 768 7 ( 7 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 81 1 ( 1 ) — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 12,113 — — — 12,113 — 12,113 +Stock options exercised, net of options forfeited in net share settlements 312 3 ( 4,258 ) — — — ( 4,255 ) — ( 4,255 ) +Restricted stock forfeited — — — — 156 ( 2,621 ) ( 2,621 ) — ( 2,621 ) +Contribution related to formation of San Mateo, net of tax of $ 3.6 million (See Note 6) +— — 45,056 — — — 45,056 — 45,056 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 61,985 ) ( 61,985 ) +Cancellation of treasury stock ( 146 ) ( 1 ) ( 2,380 ) — ( 146 ) 2,381 — — — +Current period net income — — — 584,968 — — 584,968 55,668 640,636 +Balance at December 31, 2021 117,862 $ 1,179 $ 2,077,592 $ ( 171,318 ) 12 $ ( 243 ) $ 1,907,210 $ 220,178 $ 2,127,388 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital (Accumulated deficit) retained earnings Treasury Stock Non-controlling interest in subsidiaries Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2022 117,862 $ 1,179 $ 2,077,592 $ ( 171,318 ) 12 $ ( 243 ) $ 1,907,210 $ 220,178 $ 2,127,388 +Dividends declared ($ 0.30 per share) +— — — ( 35,246 ) — — ( 35,246 ) — ( 35,246 ) +Issuance of common stock pursuant to employee stock compensation plan 1,001 10 ( 11,544 ) — — — ( 11,534 ) — ( 11,534 ) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 25 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 20,224 — — — 20,224 — 20,224 +Stock options exercised, net of options forfeited in net share settlements 157 2 ( 4,007 ) — — — ( 4,005 ) — ( 4,005 ) +Restricted stock forfeited — — — — 85 ( 2,376 ) ( 2,376 ) — ( 2,376 ) +Contributions related to formation of San Mateo, net of tax of $ 5.9 million (See Note 6) +— — 22,318 — — — 22,318 — 22,318 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 85,995 ) ( 85,995 ) +Cancellation of treasury stock ( 92 ) ( 1 ) ( 2,584 ) — ( 92 ) 2,585 — — — +Current period net income — — — 1,214,206 — — 1,214,206 72,111 1,286,317 +Balance at December 31, 2022 118,953 $ 1,190 $ 2,101,999 $ 1,007,642 5 $ ( 34 ) $ 3,110,797 $ 206,294 $ 3,317,091 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2022 2021 2020 +Operating activities +Net income (loss) $ 1,286,317 $ 640,636 $ ( 553,560 ) +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized (gain) loss on derivatives ( 18,809 ) ( 21,011 ) 32,008 +Depletion, depreciation and amortization 466,348 344,905 361,831 +Accretion of asset retirement obligations 2,421 2,068 1,948 +Full-cost ceiling impairment — — 684,743 +Stock-based compensation expense 15,123 9,039 13,625 +Deferred income tax provision (benefit) 344,480 74,710 ( 45,599 ) +Amortization of debt issuance cost and other debt related costs ( 517 ) 3,659 2,832 +Net loss on asset sales and impairment 1,311 331 2,832 +Changes in operating assets and liabilities +Accounts receivable ( 205,426 ) ( 98,456 ) 53,001 +Lease and well equipment inventory ( 2,847 ) ( 1,537 ) ( 655 ) +Prepaid expenses and other current assets ( 22,952 ) ( 11,786 ) ( 3,010 ) +Other long-term assets 175 56 1,681 +Accounts payable, accrued liabilities and other current liabilities 63,455 76,891 ( 43,844 ) +Royalties payable 23,339 28,310 ( 19,144 ) +Advances from joint interest owners 34,283 7,018 ( 10,646 ) +Other long-term liabilities ( 7,962 ) ( 1,478 ) ( 461 ) +Net cash provided by operating activities 1,978,739 1,053,355 477,582 +Investing activities +Drilling, completion and equipping capital expenditures ( 771,830 ) ( 431,136 ) ( 471,087 ) +Acquisition of oil and natural gas properties ( 155,074 ) ( 238,609 ) ( 72,809 ) +Midstream capital expenditures ( 80,051 ) ( 63,359 ) ( 234,359 ) +Acquisition of midstream assets ( 75,816 ) — — +Expenditures for other property and equipment ( 1,213 ) ( 376 ) ( 2,200 ) +Proceeds from sale of assets 46,507 4,215 4,789 +Net cash used in investing activities ( 1,037,477 ) ( 729,265 ) ( 775,666 ) +Financing activities +Purchase of senior unsecured notes ( 344,302 ) — — +Repayments of borrowings under Credit Agreement ( 300,000 ) ( 600,000 ) ( 35,000 ) +Borrowings under Credit Agreement 200,000 260,000 220,000 +Repayments of borrowings under San Mateo Credit Facility ( 150,000 ) ( 84,000 ) — +Borrowings under San Mateo Credit Facility 230,000 135,000 46,000 +Cost to enter into or amend credit facilities ( 3,725 ) ( 4,108 ) ( 660 ) +Dividends paid ( 35,246 ) ( 14,581 ) — +Contributions related to formation of San Mateo 28,250 48,626 14,700 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries — — 119,700 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries ( 85,995 ) ( 61,985 ) ( 45,570 ) +Taxes paid related to net share settlement of stock-based compensation ( 19,242 ) ( 8,211 ) ( 1,556 ) +Other ( 592 ) 706 6,725 +Net cash (used in) provided by financing activities ( 480,852 ) ( 328,553 ) 324,339 +Increase (decrease) in cash and restricted cash 460,410 ( 4,463 ) 26,255 +Cash and restricted cash at beginning of period 86,920 91,383 65,128 +Cash and restricted cash at end of period $ 547,330 $ 86,920 $ 91,383 +Supplemental disclosures of cash flow information (Note 15) +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2022, 2021 and 2020 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), and Pronto Midstream, LLC (“Pronto”) in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, customers of San Mateo and Pronto or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2022, three significant purchasers accounted for 70 % of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation ( 34 %), Plains Marketing, L.P. ( 27 %) and BP America Production Company ( 9 %). For the year ended December 31, 2021, three significant purchasers accounted for 72 % of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation ( 33 %), Plains Marketing, L.P. ( 29 %) and BP America Production Company ( 10 %). For the year ended December 31, 2020, two significant purchasers accounted for 65 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 57 %) and Exxon Mobil Corporation ( 8 %). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2022, 2021 and 2020, approximately 29 %, 39 % and 35 %, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or net realizable value and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $ 47.8 million, $ 38.4 million and $ 30.0 million of its general and administrative costs into oil and natural gas properties in 2022, 2021 and 2020, respectively. The Company capitalized $ 10.1 million, $ 4.8 million and $ 5.0 million of its interest expense into oil and natural gas properties for the years ended December 31, 2022, 2021 and 2020, respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2022, 2021 and 2020, the Company recorded depletion expense of $ 428.9 million, $ 310.1 million and $ 334.8 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10 %, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10 % discount factor is used to determine the present value of future net revenues. For the period from January through December 2022, these average oil and natural gas prices were $ 90.15 per Bbl and $ 6.36 per MMBtu, respectively. For the period from January through December 2021, these average oil and natural gas prices were $ 63.04 per Bbl and $ 3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $ 36.04 per Bbl and $ 1.99 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the years ended December 31, 2022 and 2021, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2022 and 2021. +For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $ 684.7 million, exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related deferred income tax benefit recorded net of a valuation allowance (see Note 8). +As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream Properties and Other Property and Equipment +Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. The Company capitalized $ 2.2 million, $ 1.3 million and $ 1.8 million of general and administrative costs into midstream properties in 2022, 2021 and 2020, respectively. The Company did not capitalize any interest expense into midstream properties for the years ended December 31, 2022 or 2021. The Company capitalized $ 0.5 million of interest expense into midstream properties for the year ended December 31, 2020. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment. +The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations. +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments. +Revenues +The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at Pronto’s Marlan cryogenic natural gas processing plant in Eddy County, New Mexico or San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations. +The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2022, 2021 and 2020 (in thousands). +Year Ended December 31, +2022 2021 2020 +Revenues from contracts with customers $ 3,196,699 $ 1,862,075 $ 851,135 +Lease bonus - mineral acreage — — 4,062 +Realized (loss) gain on derivatives ( 157,483 ) ( 220,105 ) 38,937 +Unrealized gain (loss) on derivatives 18,809 21,011 ( 32,008 ) +Total revenues $ 3,058,025 $ 1,662,981 $ 862,126 +Year Ended December 31, +2022 2021 2020 +Oil revenues $ 2,113,606 $ 1,205,608 $ 595,507 +Natural gas revenues 792,132 494,934 148,954 +Third-party midstream services revenues 90,606 75,499 64,932 +Sales of purchased natural gas 200,355 86,034 41,742 +Total revenues from contracts with customers $ 3,196,699 $ 1,862,075 $ 851,135 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. +The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). +The Company’s consolidated statements of operations for the years ended December 31, 2022, 2021 and 2020 include an equity-based compensation (non-cash) expense of $ 15.1 million, $ 9.0 million and $ 13.6 million, respectively. This equity-based compensation expense includes common stock issuances and restricted stock units expense totaling $ 1.0 million, $ 0.9 million and $ 1.0 million for the years ended December 31, 2022, 2021 and 2020, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statements of operations for the years ended December 31, 2022, 2021 and 2020 also include expenses of $ 31.9 million, $ 20.4 million and $ 4.0 million, respectively, related to liability-based restricted stock awards expected to be settled in cash. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2022, 2021 and 2020, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2022, 2021 and 2020. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of midstream assets and oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2022, 2021 and 2020 (in thousands, except per share data). +Year Ended December 31, +2022 2021 2020 +Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 1,214,206 $ 584,968 $ ( 593,205 ) +Weighted average common shares outstanding — denominator +Basic 118,122 116,999 116,068 +Dilutive effect of options and restricted stock units 2,009 2,164 — +Diluted weighted average common shares outstanding 120,131 119,163 116,068 +Earnings (loss) per common share attributable to Matador Resources Company shareholders +Basic $ 10.28 $ 5.00 $ ( 5.11 ) +Diluted $ 10.11 $ 4.91 $ ( 5.11 ) +A total of 2.5 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the year ended December 31, 2020 because their effects were anti-dilutive. Additionally, 0.7 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share in the losses of the Company. +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contract at December 31, 2022 was with PNC Bank, which is a lender under the Company’s reserves-based revolving credit agreement. +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2022 and 2021 (in thousands). +December 31, +2022 2021 +Oil and natural gas properties +Evaluated (subject to amortization) $ 6,862,455 $ 6,007,325 +Unproved and unevaluated (not subject to amortization) 977,502 964,714 +Total oil and natural gas properties 7,839,957 6,972,039 +Accumulated depletion ( 4,362,292 ) ( 3,933,355 ) +Net oil and natural gas properties 3,477,665 3,038,684 +Midstream properties +Midstream equipment and facilities 1,057,668 900,979 +Accumulated depreciation ( 126,706 ) ( 92,574 ) +Net midstream properties 930,962 808,405 +Other property and equipment +Furniture, fixtures and other equipment 13,257 10,923 +Software 8,225 8,225 +Leasehold improvements 11,365 10,975 +Total other property and equipment 32,847 30,123 +Accumulated depreciation ( 23,277 ) ( 20,527 ) +Net other property and equipment 9,570 9,596 +Net property and equipment $ 4,418,197 $ 3,856,685 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2022 and the year in which these costs were incurred (in thousands). +Description 2022 2021 2020 2019 2018 and prior Total +Costs incurred for +Property acquisition $ 97,748 $ 110,077 $ 40,355 $ 40,140 $ 606,740 $ 895,060 +Exploration wells 32,364 942 354 802 36 34,498 +Development wells 42,543 1,641 1,245 2,506 9 47,944 +Total $ 172,655 $ 112,660 $ 41,954 $ 43,448 $ 606,785 $ 977,502 +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2022 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $ 82.4 million at December 31, 2022. Of this total, $ 34.5 million was associated with exploration wells and $ 47.9 million was associated with development wells. The +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Company anticipates that most of the $ 82.4 million associated with these wells in progress at December 31, 2022 will be transferred to the amortization base during 2023. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2022 are costs related to the advanced preparation for wells that the Company intends to drill in the future. +NOTE 4 — LEASES +The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2022 were 3.68 % and 4.20 % for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2022 and 2021, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. +Year Ended December 31, +2022 2021 +Operating leases +Lease operating $ 15,970 $ 11,393 +Plant and other midstream services 285 36 +General and administrative 3,266 3,645 +Total operating leases (1) +19,521 15,074 +Short-term leases +Lease operating 17,437 11,234 +Plant and other midstream services 4,359 4,037 +General and administrative 34 37 +Total short-term leases (2)(3) +21,830 15,308 +Financing leases +Depreciation of assets 571 566 +Interest on lease liabilities 143 138 +Total financing leases 714 704 +Total lease expense $ 42,065 $ 31,086 +_____________________ +(1) Does not include gross payments related to drilling rig leases of $ 58.7 million and $ 31.9 million for the years ended December 31, 2022 and 2021, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2022 and 2021, respectively. +(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. +(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $ 101.5 million and $ 61.7 million for the years ended December 31, 2022 and 2021, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2022 and 2021, respectively. +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2022 and 2021, respectively (in thousands). +December 31, +2022 2021 +Operating leases +Other long-term assets $ 58,798 $ 29,519 +Other current liabilities $ ( 43,921 ) $ ( 19,649 ) +Other long-term liabilities ( 19,532 ) ( 15,340 ) +Total operating lease liabilities $ ( 63,453 ) $ ( 34,989 ) +Financing leases +Other property and equipment, at cost $ 7,425 $ 5,914 +Accumulated depreciation ( 4,470 ) ( 3,485 ) +Net property and equipment $ 2,955 $ 2,429 +Other current liabilities $ ( 685 ) $ ( 378 ) +Other long-term liabilities ( 630 ) ( 45 ) +Total financing lease liabilities $ ( 1,315 ) $ ( 423 ) +The following table presents supplemental consolidated cash flow information related to lease payments for the years ended December 31, 2022 and 2021, respectively (in thousands). +Year Ended December 31, +2022 2021 +Cash paid related to lease liabilities +Operating cash payments for operating leases $ 19,290 $ 14,430 +Investing cash payments for operating leases $ 58,693 $ 31,967 +Financing cash payments for financing leases $ 620 $ 629 +Right of use assets obtained in exchange for lease obligations entered into during the period +Operating leases $ 80,254 $ 18,454 +Financing leases $ 1,511 $ 2,241 +The following table presents the maturities of lease liabilities at December 31, 2022 (in years). +Weighted-Average Remaining Lease Term December 31, 2022 +Operating leases 1.8 +Financing leases 2.4 +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 4 — LEASES — Continued +The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2022 (in thousands). +December 31, 2022 +Operating Leases Financing Leases +2023 $ 43,921 $ 685 +2024 12,443 541 +2025 6,218 309 +2026 2,708 — +2027 572 — +Thereafter — — +Total lease payments 65,862 1,535 +Less imputed interest ( 2,409 ) ( 220 ) +Total lease obligations 63,453 1,315 +Less current obligations ( 43,921 ) ( 685 ) +Long-term lease obligations $ 19,532 $ 630 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS +The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2022 and 2021 (in thousands). +Year Ended December 31, +2022 2021 +Beginning asset retirement obligations $ 41,959 $ 38,542 +Liabilities incurred during period 4,069 2,294 +Liabilities settled during period ( 1,198 ) ( 151 ) +Revisions in estimated cash flows 10,794 86 +Divestitures during the period ( 4,304 ) ( 880 ) +Accretion expense 2,421 2,068 +Ending asset retirement obligations 53,741 41,959 +Less: current asset retirement obligations (1) +( 756 ) ( 270 ) +Long-term asset retirement obligations $ 52,985 $ 41,689 +__________________ +(1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2022 and 2021. +F-18 +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES +Business Combinations +On December 14, 2021, the Company completed an acquisition of assets from a private operator. This acquisition was accounted for as a business combination in accordance with ASC Topic 805, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. The Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, strategically located primarily within the Company’s existing acreage in its Ranger and Arrowhead asset areas. +As consideration for the business combination, the Company paid approximately $ 161.7 million in cash, subject to certain customary post-closing working capital adjustments, including adjusting for production, revenues, operating expenses and capital expenditures from August 1, 2021 to closing. In addition, the Company increased the purchase price by $ 5.0 million for each quarter during 2022 in which the average oil price, as defined in the purchase and sale agreement, was greater than $ 75.00 per barrel. The Company recorded this contingent consideration at fair value on the date of the business combination and recorded the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of operations. The change in the fair value of the contingent consideration included in “Other expense” during the years ended December 31, 2022 and 2021 was $ 11.8 million and $ 1.5 million, respectively. During the year ended December 31, 2022, the Company paid $ 15.0 million in cash related to this contingent consideration. The remaining payment of $ 5.0 million was made in the first quarter of 2023. The Company used the Monte Carlo simulation method to measure the fair value of the contingent consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy). +The allocation of the consideration given related to this business combination was as follows (in thousands), which the Company considered to be final as of September 30, 2022. +Consideration given +Allocation +Cash +$ 161,680 +Working capital adjustments ( 4,444 ) +Fair value of contingent consideration at December 14, 2021 +6,718 +Total consideration given +$ 163,954 +Allocation of purchase price +Oil and natural gas properties +Evaluated +$ 139,312 +Unproved and unevaluated +32,260 +Accrued liabilities +( 360 ) +Advances from joint interest owners ( 6,865 ) +Asset retirement obligations +( 393 ) +Net assets acquired +$ 163,954 +On June 30, 2022, the Company acquired a cryogenic gas processing plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the acquisition (the “Pronto Acquisition”) of a wholly-owned subsidiary of Summit Midstream Partners, LP that was subsequently renamed Pronto. This acquisition was also accounted for as a business combination in accordance with ASC Topic 805. In addition, the Company assumed certain takeaway capacity on a Federal Energy Regulatory Commission regulated natural gas pipeline. As consideration for the business combination, the Company paid approximately $ 77.8 million in cash, subject to certain customary post-closing purchase price adjustments. The pro forma impact of this business combination to revenues and net income for 2022 would not be material to the Company’s 2022 revenues and net income as reported. +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +The allocation of the consideration given related to this business combination was as follows (in thousands), which the Company considered to be final as of December 31, 2022. +Consideration given +Allocation +Total cash consideration given +$ 77,828 +Allocation of purchase price +Cash acquired +$ 2,012 +Property, plant & equipment +74,100 +Accounts receivable +6,093 +Other assets +296 +Accrued liabilities +( 4,673 ) +Net assets acquired +$ 77,828 +Joint Ventures +At December 31, 2022, the Company owned 51 % of San Mateo, a midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) in portions of Eddy County, New Mexico and Loving County, Texas. At December 31, 2022, Five Point owned the remaining 49 % of San Mateo. The midstream assets include (i) the Black River Processing Plant, (ii) 15 salt water disposal wells and associated commercial salt water disposal facilities and (iii) approximately 415 miles of oil gathering and transportation pipelines, natural gas gathering pipelines and produced water pipelines. The Company operates San Mateo, and San Mateo is consolidated in the Company’s financial statements, with Five Point’s interest being accounted for as a non-controlling interest. +As part of the joint venture agreements with Five Point, the Company had the potential to earn two different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $ 73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and its Wolf asset area in Loving County over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. At February 21, 2023, the Company had earned all of the potential $ 73.5 million in performance incentives. Five Point had paid $ 14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021 and the remaining $ 14.7 million in performance incentives is expected to be paid during the first quarter of 2023. Beginning in 2019, the Company had the potential to earn up to $ 150.0 million in additional deferred performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area through mid-2024, of which the Company has earned $ 62.2 million, plus additional performance incentives for securing volumes from third-party customers. During the years ended December 31, 2022 and 2021, Five Point paid $ 28.3 million and $ 33.9 million in these additional performance incentives. Both of these performance incentives are recorded when received, net of the $ 5.9 million and $ 3.6 million deferred tax impact to Matador for the years ended December 31, 2022 and 2021, respectively, in “Additional paid-in-capital” in the Company’s consolidated balance sheets. +The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15 -year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee natural gas processing agreements (see Note 14). +During the years ended December 31, 2022, 2021 and 2020, San Mateo distributed $ 89.5 million, $ 64.5 million and $ 47.4 million respectively, to the Company and $ 86.0 million, $ 62.0 million and $ 45.6 million, respectively, to Five Point. During the years ended December 31, 2022 and 2021, neither the Company nor Five Point contributed cash to San Mateo. During the year ended December 31, 2020, the Company contributed $ 75.0 million and Five Point contributed $ 119.7 million of cash to San Mateo, of which $ 23.1 million was paid to carry Matador’s proportionate interest in San Mateo Midstream II, LLC (“San Mateo II”). Five Point agreed to carry a portion of Matador’s proportionate interest as part of the formation agreement for San Mateo II. The amount that Five Point paid to carry Matador’s proportionate interest in San Mateo was recorded in “Additional paid-in capital” in the Company’s consolidated balance sheets at December 31, 2020, net of the +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +$ 4.8 million deferred tax impact to Matador related to this equity contribution. San Mateo II was merged with and into San Mateo effective October 1, 2020. +Divestitures +During 2022 and 2021, the Company converted approximately $ 46.5 million and $ 4.2 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana. +NOTE 7 — DEBT +At December 31, 2022, the Company had (i) $ 699.2 million of outstanding senior notes due 2026, (ii) no borrowings outstanding under its reserves-based revolving credit facility and (iii) approximately $ 45.6 million in outstanding letters of credit issued pursuant to its revolving credit facility. During the first quarter of 2022, the Company’s approximately $ 7.5 million unsecured U.S. Small Business Administration loan, which was issued through Iberiabank in April 2020 as part of the Paycheck Protection Program, was forgiven in full under the terms of the loan agreement and recorded as a gain on the extinguishment of debt within “Other expense” on the unaudited consolidated statement of operations. During the year ended December 31, 2022, the Company repurchased an aggregate principal amount of $ 350.8 million of its Notes for $ 344.3 million. +At December 31, 2022, San Mateo had $ 465.0 million in borrowings outstanding under its revolving credit facility and approximately $ 9.0 million in outstanding letters of credit issued pursuant to its revolving credit facility. +Credit Agreements +MRC Energy Company +On November 18, 2021, the Company entered into its Fourth Amended and Restated Credit Agreement with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85 % of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries and Pronto are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The Credit Agreement matures on October 31, 2026 or, if earlier, the date that is 180 days prior to the earliest stated redemption date of any senior notes of the Company with an outstanding principal balance in excess of $ 25.0 million. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. +In April 2022, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $ 1.35 billion to $ 2.00 billion, the borrowing commitment was increased from $ 700.0 million to $ 775.0 million and the maximum facility amount remained $ 1.50 billion. In addition, the terms of the Credit Agreement were amended to increase the sublimit for issuances of letters of credit under the Credit Agreement from $ 50 million to $ 100 million and replace the London Interbank Offered Rate (“LIBOR”) interest rate benchmark with a secured overnight financing rate administered by the Federal Reserve Bank of New York (“Adjusted Term SOFR”) (as defined in the Credit Agreement) interest rate benchmark. This April 2022 redetermination constituted the regularly scheduled May 1 redetermination. +In November 2022, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $ 2.00 billion to $ 2.25 billion. The Company elected to keep the borrowing commitment at $ 775.0 million, and the maximum facility amount remained $ 1.50 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). +In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 7 — DEBT — Continued +redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +Total deferred loan costs were $ 3.2 million at December 31, 2022, and these costs are being amortized over the term of the Credit Agreement. At December 31, 2022, the Company had no borrowings outstanding under the Credit Agreement and approximately $ 45.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. If the Company were to borrow funds under the Credit Agreement, the applicable margin that would be added to Adjusted Term SOFR would have been 1.75 % at December 31, 2022. +After giving effect to the amendment to the Credit Agreement, the applicable interest rate margin for borrowings under the Credit Agreement ranges from 1.75 % to 2.75 % per annum for borrowings bearing interest with reference to the Adjusted Term SOFR and from 0.75 % to 1.75 % per annum for borrowings bearing interest with reference to the Alternate Base Rate (as defined in the Credit Agreement), in each case depending on the level of borrowings under the Credit Agreement. In addition, the Adjusted Term SOFR includes a credit spread adjustment of 0.10 % per annum for all interest periods. The interest period for Adjusted Term SOFR borrowings may be one, three or six months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375 % to 0.50 % per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $ 75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of its assets; +• enter into commodity hedging agreements or interest rate agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and +• take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and +• a change of control, as defined in the Credit Agreement. +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 7 — DEBT — Continued +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2022. +San Mateo Midstream, LLC +On December 19, 2018, San Mateo entered into a credit facility with the lenders party thereto, currently led by Truist Bank as administrative agent (the “San Mateo Credit Facility”). In December 2022, the lenders under the San Mateo Credit Facility extended the maturity of the facility from December 19, 2023 to December 9, 2026 and increased the lender commitments from $ 450.0 million to $ 485.0 million. In addition, the lenders agreed to refresh the San Mateo Credit Facility’s accordion feature, which could expand lender commitments to up to $ 735.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. +Total deferred loan costs were $ 3.9 million at December 31, 2022, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 6.7 % at December 31, 2022. At December 31, 2022, San Mateo had $ 465.0 million in borrowings outstanding under the San Mateo Credit Facility and $ 9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between December 31, 2022 and February 21, 2023, San Mateo repaid $ 30.0 million of borrowings outstanding under the San Mateo Credit Facility. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or an Adjusted Term SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50 %, and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor plus 1.0 %, plus, in each case, an amount ranging from 1.25 % to 2.25 % per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as an Adjusted Term SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.25 % to 3.25 % per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +A commitment fee of 0.30 % to 0.50 % per annum, depending on San Mateo’s Consolidated Total Leverage Ratio, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of San Mateo’s assets; +• enter into hedging agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and +• issue equity interests in San Mateo or its restricted subsidiaries. +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 7 — DEBT — Continued +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving San Mateo or its subsidiaries; and +• a change of control, as defined in the San Mateo Credit Facility. +The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2022. +Senior Unsecured Notes +At December 31, 2022, the Company had $ 699.2 million of outstanding 5.875 % senior notes due 2026 that were registered under the Securities Act and mature September 15, 2026 (the “Notes”). Interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are jointly and severally guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries and Pronto are not Restricted Subsidiaries (as defined in the Indenture) or Guarantors of the Notes. During the year ended December 31, 2022, the Company repurchased an aggregate principal amount of $ 350.8 million of its Notes for $ 344.3 million. +The Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: +Year Redemption Price +2022 102.938 % +2023 101.469 % +2024 and thereafter 100.000 % +Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• default for 30 days in the payment when due of interest on the Notes; +• default in the payment when due of the principal of, or premium, if any, on the Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers; +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 7 — DEBT — Continued +• failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 50.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 50.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +Debt Maturities +The Credit Agreement matures on October 31, 2026. The outstanding borrowings of $ 465.0 million at December 31, 2022 under the San Mateo Credit Facility mature on December 9, 2026. The $ 699.2 million of outstanding Notes at December 31, 2022 mature on September 15, 2026. +NOTE 8 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2022 and 2021 is as follows (in thousands). +December 31, +2022 2021 +Deferred tax assets +Net operating loss carryforwards $ 12,874 $ 129,651 +Unrealized loss on derivatives — 3,729 +Percentage depletion carryover 8 1,770 +Compensation 14,184 9,838 +Lease liabilities 12,585 4,866 +Other 1,926 9,410 +Total deferred tax assets 41,577 159,264 +Valuation allowance on deferred tax assets ( 11,322 ) ( 10,599 ) +Total deferred tax assets, net of valuation allowance 30,255 148,665 +Deferred tax liabilities +Unrealized gain on derivatives ( 995 ) — +Property and equipment ( 368,283 ) ( 179,153 ) +Less than wholly-owned subsidiaries ( 63,388 ) ( 39,900 ) +Lease right of use assets ( 12,585 ) ( 4,866 ) +Other ( 13,355 ) ( 2,684 ) +Total deferred tax liabilities ( 458,606 ) ( 226,603 ) +Net deferred tax liabilities $ ( 428,351 ) $ ( 77,938 ) +At December 31, 2020, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. Due to a variety of factors, including the Company’s significant net income in 2021, the Company’s federal valuation allowance was reversed as of September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 8 — INCOME TAXES — Continued +The current income tax provision and the deferred income tax provision for the years ended December 31, 2022, 2021 and 2020 were comprised of the following (in thousands). +Year Ended December 31, +2022 2021 2020 +Current income tax provision +Federal income tax $ 31,335 $ — $ — +State income tax 23,542 — — +Net current income tax provision $ 54,877 $ — $ — +Deferred income tax provision (benefit) +Federal income tax $ 302,486 $ 44,883 $ ( 25,675 ) +State income tax 41,994 29,827 ( 19,924 ) +Net deferred income tax provision (benefit) $ 344,480 $ 74,710 $ ( 45,599 ) +Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2022, 2021 and 2020 is as follows (in thousands). +Year Ended December 31, +2022 2021 2020 +Federal tax expense (benefit) at statutory rate (1) +$ 353,992 $ 150,223 $ ( 125,823 ) +State income tax expense (benefit) 59,870 26,646 ( 20,607 ) +Permanent differences ( 15,227 ) ( 2,078 ) ( 3,114 ) +Change in federal valuation allowance — ( 103,262 ) 103,262 +Change in state valuation allowance 722 3,181 683 +Total income tax provision (benefit) $ 399,357 $ 74,710 $ ( 45,599 ) +__________________ +(1) The statutory federal tax rate was 21% for the years ended December 31, 2022, 2021 and 2020. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2019. The earliest tax year open for examination for the State of Texas tax return is 2018. +The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2022, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. +NOTE 9 — STOCK-BASED COMPENSATION +In 2012, the Company’s Board of Directors (the “Board”) adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. +In 2019, the Board adopted and shareholders approved the 2019 Incentive Plan. In April 2022, the Board adopted, subject to shareholder approval, the first amendment to the 2019 Long-Term Incentive Plan, authorizing an additional 3,725,000 shares of common stock for issuance to employees, directors, contractors or advisors of the Company. In June 2022, the Company’s shareholders approved such amendment. As of December 31, 2022, the 2019 Incentive Plan provided for a maximum of 4,174,443 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +The 2012 Incentive Plan and 2019 Incentive Plan are administered by the independent members of the Board, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. +During the years ended December 31, 2022, 2021 and 2020, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. +In April 2022, the Board adopted, subject to shareholder approval, an Employee Stock Purchase Plan (the “ESPP”). The purpose of the ESPP is to encourage and enable the Company’s eligible employees to acquire an interest in the Company through the ownership of common stock. In June 2022, the Company’s shareholders approved and authorized a maximum of 4.0 million shares of common stock to be purchased under the ESPP. At December 31, 2022, the Company had 3,977,456 remaining shares available for issuance under the ESPP. +Stock Options +Under the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted and are outstanding to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or 10 years. The 2012 Incentive Plan defines fair market value as the closing price of Matador’s common stock on the date of grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing price of Matador’s common stock on the trading day prior to the date of grant. The Company did not grant stock option awards during the years ended December 31, 2022, 2021 and 2020. +Summarized information about stock options outstanding at December 31, 2022 under the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows. +Number of +options +(in thousands) +Weighted +average +exercise price +Options outstanding at December 31, 2021 603 $ 22.92 +Options granted — $ — +Options exercised ( 445 ) $ 24.35 +Options forfeited ( 8 ) $ 14.80 +Options expired — $ — +Options outstanding at December 31, 2022 150 $ 19.11 +Options outstanding at +December 31, 2022 +Options exercisable at +December 31, 2022 +Range of exercise prices +Shares +outstanding (in thousands) +Weighted +average +remaining +contractual +life Weighted +average +exercise +price +Shares +exercisable (in thousands) +Weighted +average +exercise +price +$ 14.48 - $ 14.80 +103 2.66 $ 14.80 103 $ 14.80 +$ 26.86 - $ 29.68 +47 0.74 $ 28.60 47 $ 28.60 +At December 31, 2022, the aggregate intrinsic value for both outstanding and exercisable options was $ 5.7 million, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2022 was 2.06 years. +The total intrinsic value of options exercised during the years ended December 31, 2022, 2021 and 2020 was $ 14.4 million, $ 15.8 million and $ 0.3 million, respectively. At December 31, 2022, the Company did not have any unvested stock options or unrecognized compensation expense associated with unvested stock options. +The fair value of options vested during 2022, 2021 and 2020 was $ 0.8 million, $ 3.0 million and $ 6.7 million, respectively. +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +Service-Based Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2022, 2021 and 2020 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year period. Performance-based restricted stock units granted in 2022 and 2021 vest in an amount between zero and 200 % of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2024 and 2023, respectively, as compared to a designated peer group, and will be settled in equity. +Equity-Based +A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2022 is presented below (in thousands, except fair value). +Restricted Stock Restricted Stock Units +Service Based Service Based Performance Based +Non-vested restricted stock and +restricted stock units Shares Weighted +average +fair +value Shares Weighted +average +fair +value Shares Weighted +average +fair +value +Non-vested at December 31, 2021 589 $ 24.59 33 $ 33.39 963 $ 20.26 +Granted 236 $ 45.58 16 $ 66.16 230 $ 65.49 +Vested (1) +( 126 ) $ 24.07 ( 33 ) $ 33.39 ( 597 ) $ 1.74 +Forfeited ( 41 ) $ 19.12 — $ — — $ — +Non-vested at December 31, 2022 658 $ 24.59 16 $ 66.16 596 $ 56.31 +__________________ +(1) On December 31, 2022, 597,414 of the performance-based awards that were granted in 2020 vested. The vested units earned 175% for each vested award representing 1,045,472 aggregate shares of common stock, which were issued on December 31, 2022. +Liability-Based +A summary of the non-vested liability-based restricted stock units as of December 31, 2022 is presented below (in thousands). +Non-vested +restricted stock units Shares +Non-vested at December 31, 2021 1,102 +Granted 226 +Vested ( 587 ) +Forfeited ( 19 ) +Non-vested at December 31, 2022 722 +During the years ended December 31, 2022, 2021 and 2020, the Company settled 587,251 , 487,252 and 226,363 liability-based awards, respectively, for $ 30.8 million, $ 12.4 million and $ 2.4 million in cash, respectively. +At December 31, 2022, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ 114.1 million, of which $ 41.3 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. +At December 31, 2022, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $ 56.1 million, of which $ 23.4 million is expected to be settled in cash, based on the +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.7 years. +The fair value of restricted stock and restricted stock units vested during 2022, 2021 and 2020 was $ 99.6 million, $ 51.9 million and $ 8.4 million, respectively. +Summary +During the years ended December 31, 2022, 2021 and 2020, the total expense attributable to stock options was $ 0.5 million, $ 1.0 million and $ 3.4 million, respectively. During the years ended December 31, 2022, 2021 and 2020, the total expense attributable to restricted stock and restricted stock units was $ 51.6 million, $ 36.3 million and $ 17.7 million, respectively. During the years ended December 31, 2022, 2021 and 2020, the Company capitalized $ 5.0 million, $ 7.2 million and $ 3.6 million, respectively, related to stock-based compensation and expensed the remaining $ 47.1 million, $ 30.0 million and $ 17.6 million, respectively. +The total tax benefit recognized for all stock-based compensation was $ 11.0 million, $ 7.9 million and $ 4.5 million for the years ended December 31, 2022, 2021 and 2020, respectively. +NOTE 10 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3 % of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $ 1.8 million, $ 1.6 million and $ 1.4 million in 2022, 2021 and 2020, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $ 2.3 million, $ 2.1 million and $ 1.8 million in 2022, 2021 and 2020, respectively. The Company made no additional contributions in any reporting period presented. +NOTE 11 — EQUITY +Common Stock Dividend +In February 2022 and April 2022, the Board declared quarterly cash dividends of $ 0.05 per share of common stock, each of which totaled $ 5.9 million and were paid on March 14, 2022 and June 3, 2022, respectively. In June 2022, the Board amended the Company’s dividend policy to increase the quarterly dividend to $ 0.10 per share of common stock. In July 2022 and October 2022, the Board declared quarterly cash dividends of $ 0.10 per share of common stock, each of which totaled $ 11.7 million and were paid on September 1, 2022 and December 1, 2022, respectively. In December 2022, the Board amended the Company’s dividend policy to increase the quarterly dividend to $ 0.15 per share of common stock for future dividend payments. On February 15, 2023, the Board declared a quarterly cash dividend of $ 0.15 per share of common stock payable on March 9, 2023 to shareholders of record as of February 27, 2023. The Board declared a quarterly cash dividend of $ 0.025 per share of common stock in each of the first three quarters of 2021 and, in the fourth quarter of 2021, the Board declared a quarterly cash dividend of $ 0.05 per share of common stock. Total cash dividends declared and paid totaled $ 35.2 million and $ 14.6 million, respectively, during the years December 31, 2022 and 2021. There were no cash dividends declared or paid prior to 2021. +Treasury Stock +On October 20, 2022, October 21, 2021 and October 22, 2020, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2022, 2021 and 2020, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2022, 2021 and 2020 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2021, 2020 and 2019 +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2022, the Company had one costless collar open and in place to mitigate its exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. At December 31, 2022, the contract was set to expire during the first quarter of 2023. The Company had no open contracts associated with oil or NGL prices at December 31, 2022. +The following is a summary of the Company’s open costless collar contract at December 31, 2022. +Notional Quantity (MMBtu) Weighted Average Price Floor ($/MMBtu) Weighted Average Price Ceiling ($/MMBtu) Fair Value of Asset (Liability) (thousands) +Commodity Calculation Period +Natural Gas 01/01/2023 - 03/31/2023 2,400,000 $ 6.00 $ 14.00 3,931 +Total open costless collar contracts $ 3,931 +Between December 31, 2022 and February 21, 2023, the Company entered into a Waha-Henry Hub basis swap contract for natural gas. The basis swap contract included approximately 16,700,000 MMBtu for February 2023 to December 2023 with a fixed price of ($ 1.85 ) per MMBtu. +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2022 and December 31, 2021 (in thousands). +Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets +December 31, 2022 +Current assets $ 3,931 $ — $ 3,931 +Current liabilities — — — +Total $ 3,931 $ — $ 3,931 +December 31, 2021 +Current assets $ 215,145 $ ( 213,174 ) $ 1,971 +Current liabilities ( 230,023 ) 213,174 ( 16,849 ) +Total $ ( 14,878 ) $ — $ ( 14,878 ) +The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). +Year Ended December 31, +Type of Instrument Location in Statements of Operations 2022 2021 2020 +Derivative Instrument +Oil Revenues: Realized (loss) gain on derivatives $ ( 75,806 ) $ ( 194,058 ) $ 38,937 +Natural Gas Revenues: Realized loss on derivatives ( 81,677 ) ( 26,047 ) — +Realized (loss) gain on derivatives ( 157,483 ) ( 220,105 ) 38,937 +Oil Revenues: Unrealized gain (loss) on derivatives 14,727 26,857 ( 37,703 ) +Natural Gas Revenues: Unrealized gain (loss) on derivatives 4,082 ( 5,846 ) 5,695 +Unrealized gain (loss) on derivatives 18,809 21,011 ( 32,008 ) +Total $ ( 138,674 ) $ ( 199,094 ) $ 6,929 +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 13 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2022 and 2021 (in thousands). +Fair Value Measurements at +December 31, 2022 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Natural gas derivatives $ — $ 3,931 $ — $ 3,931 +Total $ — $ 3,931 $ — $ 3,931 +Fair Value Measurements at +December 31, 2021 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Oil derivatives and basis swaps $ — $ ( 14,727 ) $ — $ ( 14,727 ) +Natural gas derivatives — ( 151 ) — ( 151 ) +Contingent consideration related to business combination — — ( 8,203 ) $ ( 8,203 ) +Total $ — $ ( 14,878 ) $ ( 8,203 ) $ ( 23,081 ) +Additional disclosures related to derivative financial instruments are provided in Note 12. +Other Fair Value Measurements +At December 31, 2022 and 2021, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities. +At December 31, 2022 and 2021, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2022 and 2021, the fair value of the Notes was $ 675.7 million and $ 1.08 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 13 — FAIR VALUE MEASUREMENTS — Continued +the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2022 and 2021. +NOTE 14 — COMMITMENTS AND CONTINGENCIES +Processing, Transportation and Produced Water Disposal Commitments +Firm Commitments +From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $ 48.3 million and $ 48.7 million for deliveries under these agreements during the years ended December 31, 2022 and 2021, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2022, the total deficiencies required to be paid by the Company under these agreements would be approximately $ 541.1 million. +San Mateo Commitments +The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15 -year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2022 was approximately $ 292.0 million. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $ 17.7 million at December 31, 2022. +At December 31, 2022, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $ 26.0 million at December 31, 2022. The Company expects these costs to be incurred within the next year. +At December 31, 2022, the Company had outstanding commitments of $ 29.8 million to purchase 12 compressors to be utilized in San Mateo and Pronto operations. The Company expects these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 15 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2022 and 2021 (in thousands). +December 31, +2022 2021 +Accrued evaluated and unproved and unevaluated property costs $ 112,766 $ 128,598 +Accrued midstream properties costs 11,623 7,799 +Accrued lease operating expenses 46,975 32,182 +Accrued interest on debt 10,461 18,232 +Accrued asset retirement obligations 756 270 +Accrued partners’ share of joint interest charges 42,199 17,460 +Accrued payable related to purchased natural gas 11,158 11,284 +Other 25,372 37,458 +Total accrued liabilities $ 261,310 $ 253,283 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2022, 2021 and 2020 (in thousands). +Year Ended December 31, +2022 2021 2020 +Cash paid for income taxes $ 63,500 $ — $ — +Cash paid for interest expense, net of amounts capitalized $ 72,561 $ 74,843 $ 76,880 +Increase (decrease) in asset retirement obligations related to mineral properties $ 9,111 $ 1,091 $ ( 208 ) +Increase in asset retirement obligations related to midstream properties $ 251 $ 257 $ 690 +(Decrease) increase in liabilities for drilling, completion and equipping capital expenditures $ ( 13,304 ) $ 80,255 $ ( 26,126 ) +(Decrease) increase in liabilities for acquisition of oil and natural gas properties $ ( 2,531 ) $ 2,981 $ ( 2,346 ) +Increase (decrease) in liabilities for midstream capital expenditures $ 3,824 $ ( 4,478 ) $ ( 33,609 ) +Stock-based compensation expense recognized as liability $ 31,906 $ 24,494 $ 3,702 +Transfer of inventory from (to) oil and natural gas properties $ 148 $ ( 398 ) $ 608 +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2022 2021 2020 +Cash $ 505,179 $ 48,135 $ 57,916 +Restricted cash 42,151 38,785 33,467 +Total cash and restricted cash $ 547,330 $ 86,920 $ 91,383 +NOTE 16 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 16 — SEGMENT INFORMATION — Continued +natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations, are conducted through San Mateo (see Note 6). In addition, on June 30, 2022, an indirect wholly-owned subsidiary of the Company acquired a cryogenic gas processing plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. Neither San Mateo nor Pronto is a guarantor of the Notes. +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2022 +Oil and natural gas revenues $ 2,897,336 $ 8,402 $ — $ — $ 2,905,738 +Midstream services revenues — 298,184 — ( 207,578 ) 90,606 +Sales of purchased natural gas 116,772 83,583 — — 200,355 +Realized loss on derivatives ( 157,483 ) — — — ( 157,483 ) +Unrealized gain on derivatives 18,809 — — — 18,809 +Expenses (1) +1,177,104 227,556 101,673 ( 207,578 ) 1,298,755 +Operating income (2) +$ 1,698,330 $ 162,613 $ ( 101,673 ) $ — $ 1,759,270 +Total assets (3) +$ 4,022,609 $ 1,016,580 $ 515,316 $ — $ 5,554,505 +Capital expenditures (4) +$ 903,518 $ 158,544 $ 1,213 $ — $ 1,063,275 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 429.7 million and $ 34.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.0 million. +(2) Includes $ 72.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 131.0 million attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ 75.8 million in midstream acquisition expenditures and $ 39.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2021 +Oil and natural gas revenues $ 1,695,032 $ 5,510 $ — $ — $ 1,700,542 +Midstream services revenues — 228,817 — ( 153,318 ) 75,499 +Sales of purchased natural gas 47,398 38,636 — — 86,034 +Realized loss on derivatives ( 220,105 ) — — — ( 220,105 ) +Unrealized gain on derivatives 21,011 — — — 21,011 +Expenses (1) +794,880 142,444 85,899 ( 153,318 ) 869,905 +Operating (loss) income (2) +$ 748,456 $ 130,519 $ ( 85,899 ) $ — $ 793,076 +Total assets (3) +$ 3,324,681 $ 879,672 $ 57,800 $ — $ 4,262,153 +Capital expenditures (4) +$ 778,191 $ 59,361 $ 376 $ — $ 837,928 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 310.9 million and $ 31.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.6 million. +(2) Includes $ 55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2020 +Oil and natural gas revenues $ 741,092 $ 3,369 $ — $ — $ 744,461 +Midstream services revenues — 166,194 — ( 101,262 ) 64,932 +Sales of purchased natural gas 20,736 21,006 — — 41,742 +Lease bonus - mineral acreage 4,062 — — — 4,062 +Realized gain on derivatives 38,937 — — — 38,937 +Unrealized loss on derivatives ( 32,008 ) — — — ( 32,008 ) +Expenses (1) +1,334,378 97,599 52,910 ( 101,262 ) 1,383,625 +Operating income (loss) (2) +$ ( 561,559 ) $ 92,970 $ ( 52,910 ) $ — $ ( 521,499 ) +Total assets (3) +$ 2,782,819 $ 836,509 $ 67,952 $ — $ 3,687,280 +Capital expenditures (4) +$ 518,198 $ 201,440 $ 2,200 $ — $ 721,838 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 335.8 million and $ 23.3 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $ 684.7 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $ 2.7 million. +(2) Includes $ 39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2022, 2021 and 2020 +NOTE 17 — SUBSEQUENT EVENTS +On January 24, 2023, a wholly-owned subsidiary of the Company entered into a definitive agreement to acquire Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped acreage located primarily in Lea County, New Mexico and Ward County, Texas (the “Advance Acquisition”). The consideration for the Advance Acquisition is expected to consist of $ 1.6 billion in cash, subject to customary closing adjustments, including for working capital and title and environmental defects, plus additional cash consideration of $ 7.5 million for each month during 2023 in which the average price of crude oil (as defined in the securities purchase agreement) exceeds $ 85 per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected to close in the second quarter of 2023 with an effective date of January 1, 2023. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2022, 2021 and 2020 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2022, 2021 and 2020 (in thousands). +Year Ended December 31, +2022 2021 2020 +Property acquisition costs +Proved $ 36,985 $ 145,759 $ 8,003 +Unproved and unevaluated 97,127 104,582 61,984 +Exploration costs 136,209 51,534 29,370 +Development costs 643,947 476,316 418,840 +Total costs incurred (1) +$ 914,268 $ 778,191 $ 518,197 +__________________ +(1) Excludes midstream-related development and corporate costs of approximately $159.8 million, $59.7 million and $203.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2022 and 2020, a majority of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests, while for the year ended December 31, 2021, 58% of the Company’s property acquisition costs resulted from the acquisition of proved properties. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. The Company capitalized $7.5 million of geological and geophysical costs, which are included as exploration costs in the table above, for the year ended December 31, 2021. The Company did not capitalize any geological and geophysical costs in 2022 or 2020. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were an increase of $10.7 million, an increase of $1.4 million and a reduction of $0.2 million for the years ended December 31, 2022, 2021 and 2020, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $47.8 million, $38.4 million and $30.0 million of these internal costs for the years ended December 31, 2022, 2021 and 2020, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $10.1 million, $4.8 million and $5.0 million of its interest expense for the years ended December 31, 2022, 2021 and 2020, respectively, excluding midstream-related capitalized interest expense. +Oil and Natural Gas Reserves +Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2022, 2021 and 2020 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2022, 2021 and 2020 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2022, these average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2022, 2021 and 2020 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +Net Proved Reserves +Oil Natural Gas Oil +Equivalent +(MBbl) (MMcf) (MBOE) +Total at December 31, 2019 147,991 627,238 252,531 +Revisions of prior estimates 6,587 19,444 9,828 +Net acquisitions of minerals-in-place 11 1,078 190 +Extensions and discoveries 21,291 84,043 35,297 +Production (15,931) (69,501) (27,514) +Total at December 31, 2020 159,949 662,302 270,332 +Revisions of prior estimates 14,346 165,423 41,916 +Net acquisitions of minerals-in-place 7,533 11,976 9,529 +Extensions and discoveries 17,318 94,532 33,074 +Production (17,840) 81,686 (31,454) +Total at December 31, 2021 181,306 852,547 323,397 +Revisions of prior estimates (2,502) 13,190 (302) +Net acquisitions (divestitures) of minerals-in-place 1,239 (1,332) 1,017 +Extensions and discoveries 38,189 197,497 71,105 +Production (21,943) (99,308) (38,495) +Total at December 31, 2022 196,289 962,594 356,722 +Proved Developed Reserves +December 31, 2019 59,667 276,258 105,710 +December 31, 2020 69,647 323,160 123,507 +December 31, 2021 102,233 546,173 193,262 +December 31, 2022 116,030 632,858 221,507 +Proved Undeveloped Reserves +December 31, 2019 88,324 350,980 146,821 +December 31, 2020 90,301 339,142 146,825 +December 31, 2021 79,073 306,374 130,135 +December 31, 2022 80,259 329,736 135,215 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2022, 2021 and 2020. +The Company’s proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. The Company’s proved oil and natural gas reserves increased by 71.8 million BOE and the Company produced 38.5 million BOE during the year ended December 31, 2022, resulting in a net increase of 33.3 million BOE. The Company added 71.1 million BOE in proved reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations drilled during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2022, but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As the +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2022, 2021 and 2020 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 7.4 million BOE to proved reserves at a future date. +The Company’s proved developed oil and natural gas reserves increased 15% from 193.3 million BOE at December 31, 2021 to 221.5 million BOE at December 31, 2022. The Company’s proved developed oil and natural gas reserves increased by 66.7 million BOE and the Company produced 38.5 million BOE during the year ended December 31, 2022, resulting in a net increase of 28.2 million BOE. The Company added 24.7 million BOE in proved developed reserves through extensions and discoveries during 2022, which resulted from new well locations drilled during 2022 to establish proved reserves. The Company realized approximately 2.9 million BOE in net upward revisions to prior estimates, most of which was attributable to the higher commodity prices used to estimate proved reserves at December 31, 2022, which resulted in longer estimated economic lives for certain of our producing properties. In addition, the Company converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022, primarily in our Ranger, Stateline, Antelope Ridge and Rustler Breaks asset areas. In addition, the Company realized 0.8 million BOE in net upward revisions to our proved developed reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. +The Company’s proved undeveloped oil and natural gas reserves increased 4% from 130.1 million BOE at December 31, 2021 to 135.2 million at December 31, 2022. The Company added 53.8 million BOE in proved undeveloped reserves through extensions and discoveries during 2022, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022 but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. The Company realized approximately 3.2 million BOE in net downward revisions to our prior estimates of proved undeveloped reserves, most of which was attributable to forecast updates at December 31, 2022. In addition, the Company realized 0.3 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. During 2022, the Company also converted 38.4 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin during 2022. +At December 31, 2022, the Company’s proved reserves were comprised of 55% oil and 45% natural gas and were approximately 62% proved developed and 38% proved undeveloped. This increase in the Company’s proved developed reserves to 62% of its total proved reserves at December 31, 2022 reflected a continued increase in the Company’s percentage of proved developed reserves, as compared to 60% and 46% proved developed reserves at December 31, 2021 and 2020, respectively. +The Company’s proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. The Company’s proved oil and natural gas reserves increased by 84.5 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021, resulting in a net increase of 53.1 million BOE. The Company added 33.1 million BOE in proved reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of our properties in the Delaware Basin. As the Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 16.3 million BOE to proved reserves at a future date. The Company also realized 41.9 million BOE in net upward revisions to prior estimates, 96% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its properties. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its properties. In addition, the Company realized 9.5 million BOE in net upward revisions to its proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. +The Company’s proved oil and natural gas reserves increased from 252.5 million BOE at December 31, 2019 to 270.3 million BOE at December 31, 2020. The Company’s proved oil and natural gas reserves increased by 45.3 million BOE and the Company produced 27.5 million BOE during the year ended December 31, 2020, resulting in a net increase of 17.8 million BOE. The Company added 35.3 million BOE in proved reserves through extensions and discoveries during 2020, of which 15.2 million BOE resulted from new well locations drilled during 2020 to establish proved developed reserves and 20.1 million BOE +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2022, 2021 and 2020 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +consisted primarily of new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2020. The Company also realized 9.8 million BOE in net upward revisions to prior estimates at December 31, 2020, which included positive revisions to prior estimates of 31.2 million BOE attributable primarily to revisions to prior forecasts resulting from better-than-expected well performance during 2020, which was offset by negative revisions to prior estimates of 21.4 million BOE primarily resulting from lower weighted oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. The Company’s proved developed oil and natural gas reserves increased to 123.5 million BOE at December 31, 2020 from 105.7 million BOE at December 31, 2019, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2020, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 46% proved developed and 56% proved undeveloped. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2022, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. For the period from January through December 2021, the comparable average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, the comparable average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2022, 2021 and 2020 (in thousands). +Year Ended December 31, +2022 2021 2020 +Future cash inflows $ 24,952,118 $ 15,174,065 $ 6,587,343 +Future production costs (6,752,752) (4,588,677) (2,606,956) +Future development costs (1,776,029) (1,251,581) (1,075,317) +Future income tax expense (3,935,271) (1,836,009) (228,848) +Future net cash flows 12,488,066 7,497,798 2,676,222 +10% annual discount for estimated timing of cash flows (5,504,863) (3,122,373) (1,091,823) +Standardized measure of discounted future net cash flows $ 6,983,203 $ 4,375,425 $ 1,584,399 +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2022, 2021 and 2020 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2022, 2021 and 2020 (in thousands). +Year Ended December 31, +2022 2021 2020 +Balance, beginning of period $ 4,375,425 $ 1,584,399 $ 2,033,983 +Net change in sales and transfer prices and in production (lifting) costs related to future production 4,046,504 3,347,910 (1,126,777) +Changes in estimated future development costs (744,687) (238,871) 177,074 +Sales and transfers of oil and natural gas produced during the period (2,466,440) (1,412,591) (546,169) +Net purchases of reserves in place 28,841 178,695 1,803 +Net change due to extensions and discoveries 2,017,170 620,235 296,617 +Net change due to revisions in estimates of reserves quantities (8,576) 786,061 93,066 +Previously estimated development costs incurred during the period 434,336 240,664 253,165 +Accretion of discount 475,474 165,799 240,728 +Other 1,982 1,737 16 +Net change in income taxes (1,176,826) (898,613) 160,893 +Standardized measure of discounted future net cash flows $ 6,983,203 $ 4,375,425 $ 1,584,399 +F-43 \ No newline at end of file diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/filing_metadata.csv b/raw/filings/0001520006/2022/0001520006-23-000056/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e1eed0efe9f1a07cac2d6d0278b2c029861eb564 --- /dev/null +++ b/raw/filings/0001520006/2022/0001520006-23-000056/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2023-03-01,2022-12-31,2023-03-02T02:06:49.000Z,0001520006-23-000056,mtdr-20221231.htm,10-K,15012740,1,1,https://www.sec.gov/Archives/edgar/data/1520006/000152000623000056/mtdr-20221231.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000623000056/,2022,2022,1 diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/item1.txt b/raw/filings/0001520006/2022/0001520006-23-000056/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..3204bd0e031463f17a6305c7b6d2c42172b99e67 --- /dev/null +++ b/raw/filings/0001520006/2022/0001520006-23-000056/item1.txt @@ -0,0 +1,630 @@ +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries and (iv) references to “Pronto” refer to Pronto Midstream, LLC, and the “Pronto Acquisition” refers to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +2 +Table of Contents +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Pronto; +• maintain our financial discipline; +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs and do so in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas prices improved significantly during 2021 and 2022. These factors, along with the successful execution of our business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2022, as well as to increases in our oil and natural gas revenues and cash flows. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down borrowings, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC, our joint venture partner in San Mateo (“Five Point”). Further, we concluded several important financing transactions in 2022, including increasing the borrowing base under our Credit Agreement (as defined below) and extending the maturity of and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved important milestones in 2022, including the addition of produced water disposal capacity and being awarded several new customer contracts. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2022 Highlights +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2022, we achieved record oil, natural gas and average daily oil equivalent production. In 2022, we produced 21.9 million Bbl of oil, an increase of 23%, as compared to 17.8 million Bbl of oil produced in 2021. We also produced 99.3 Bcf of natural gas, an increase of 22% from 81.7 Bcf of natural gas produced in 2021. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of 22%, as compared to 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, for the year ended December 31, 2021. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2022 and 2021. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, an increase of 10% from 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, at December 31, 2021. The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and PV-10 were primarily a result of the significantly higher unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to +3 +Table of Contents +December 31, 2021. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2022, proved developed reserves included 116.0 million Bbl of oil and 632.9 Bcf of natural gas, and proved undeveloped reserves included 80.3 million Bbl of oil and 329.7 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas reserves at December 31, 2022. Proved developed reserves and proved oil reserves comprised 60% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2021. The improvement in proved developed reserves as a percentage of our total proved oil and natural gas reserves to 62% at December 31, 2022 from 60% at December 31, 2021 was primarily attributable to the development and conversion of approximately 38.4 million BOE of our proved undeveloped reserves to proved developed reserves and the addition of 24.7 million BOE in extensions and discoveries primarily in the Delaware Basin in 2022. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2023. +We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin in 2022, including 81 gross (64.5 net) operated and 63 gross (5.4 net) non-operated wells. At December 31, 2022, our total acreage position in the Delaware Basin was approximately 237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust asset areas in Loving County, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021. We expect our Delaware Basin production to increase in 2023 as we continue the delineation and development of these asset areas. +During 2022, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +• 11 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a staggered fashion in early 2022; these 11 Voni wells have produced in aggregate approximately 3.6 million BOE in 11 months of production; +• the third group of nine Rodney Robinson wells in the western portion of our Antelope Ridge asset area in March 2022; these nine Rodney Robinson wells have produced in aggregate approximately 3.1 million BOE in 10 months of production; +• 11 Rustler Breaks wells in April 2022; these 11 wells have produced in aggregate approximately 2.6 million BOE in almost nine months of production; +• 16 Antelope Ridge wells in the second half of 2022; these 16 wells have produced in aggregate approximately 1.6 million BOE in 2022; and +• 12 Ranger wells in the fourth quarter of 2022. +In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2022 included: +• continued drilling of longer laterals, whereby 90% of the operated horizontal wells we turned to sales in 2022 had lateral lengths of two miles or greater, as compared to 74% in 2020; and +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2022 of $772.5 million, which was at the low end of our revised estimated range for 2022 D/C/E capital expenditures of $765 to $835 +4 +Table of Contents +million as provided on July 26, 2022 and affirmed on October 25, 2022, which included the addition of a seventh operated drilling rig in September 2022. +Capital Resources and Financing Highlights +During 2022, we achieved several significant and important capital resources objectives, which included: +• the generation of free cash flow in all four quarters of 2022; +• the repayment of all outstanding borrowings under our revolving credit facility, resulting in no outstanding borrowings under that facility at December 31, 2022; +• the repurchase of $350.8 million of our outstanding senior notes; +• the amendments of our dividend policy in the second and fourth quarters of 2022, pursuant to which we increased the quarterly cash dividend from $0.05 per share of common stock to $0.15 per share of common stock; and +• the receipt of $28.3 million in performance incentives directly from Five Point. +In addition, we concluded several important financing transactions in 2022 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the spring and fall redetermination processes revised our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.25 billion, as compared to $1.35 billion at December 31, 2021, (ii) increase the elected borrowing commitment to $775.0 million, as compared to $700.0 million at December 31, 2021, (iii) reaffirm the maximum facility amount at $1.5 billion and (iv) add one new bank to our lending group; and +• the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in December 2022 to (i) extend the maturity date by three years from December 2023 to December 2026, (ii) increase the lender commitments under the San Mateo Credit Facility from $450.0 million to $485.0 million, (iii) refresh the accordion feature that provides for potential increases in lender commitments to up to $735.0 million, as compared to $700.0 million previously, and (iv) add one new bank to San Mateo’s lending group. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point, and through Pronto, which is a wholly-owned subsidiary. +San Mateo achieved strong operating results in 2022, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2022 and 2021. +During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. +At December 31, 2022, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the acreage in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); +• Oil Assets : Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +5 +Table of Contents +• Produced Water Assets : 15 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +On June 30, 2022, we acquired a wholly-owned subsidiary of Summit Midstream Partners, LP that was subsequently renamed Pronto, which owned a cryogenic gas processing plant with a designed inlet capacity of 60 MMcf of natural gas per day (the “Marlan Processing Plant”), three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +Environmental, Social and Governance (“ESG”) Initiatives +We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and the highest applicable regulatory and legal standards. More recently, we have begun formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB). +Highlights from our ESG initiatives, which generally relate to our operations in 2021 except as otherwise noted, include: +• Decreased direct greenhouse gas emissions intensity by 28% in 2021, as compared to 2020; +• Decreased methane emissions intensity by 48% in 2021, as compared to 2020; +• Decreased flaring intensity by 53% in 2021, as compared to 2020; +• Increased use of non-fresh water to 96% of total water consumption in 2021; +• Increased number of wells utilizing recycled produced water to 72% of total wells completed in 2021; +• Transported 99% of operated produced water and 89% of operated produced oil by pipeline in 2022; +• Incurred no employee lost time incidents during approximately 3.3 million employee man-hours from 2017 to 2022; and +• Provided approximately 16,000 hours of employee continuing education, equating to approximately 50 hours per employee in 2022. +These sustainability metrics have been calculated using the best information available to us. The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2022 data from our ESG initiatives in the second half of 2023 in connection with the preparation of our 2022 Sustainability Report. +Recent Developments +On January 24, 2023, our wholly-owned subsidiary entered into a definitive agreement to acquire Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped acreage located primarily in Lea County, New Mexico and Ward County, Texas (the “Advance Acquisition”). The consideration for the Advance Acquisition is expected to consist of $1.6 billion in cash, subject to customary closing adjustments, including for working capital and for title and environmental defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the average price of crude oil (as defined in the securities purchase agreement) exceeds $85 per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected to close in the second quarter of 2023 with an effective date of January 1, 2023. +We estimate the total proved oil and natural gas reserves associated with these properties are approximately 106.4 million BOE (73% oil) at December 31, 2022. These reserves estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Other highlights of the Advance Acquisition include: +• Estimated production in the first quarter of 2023 of 24,500 to 25,500 BOE per day (74% oil); +• Approximately 18,500 net acres (99% held by production) in the core of the northern Delaware Basin, most of which is strategically located in our Ranger asset area in Lea County, New Mexico near our existing properties; +• 206 gross (174 net) operated locations (84% working interest) and 200 gross (29 net) non-operated locations (15% working interest); +• 21 gross (20 net) drilled but uncompleted wells expected to be turned to sales in the second half of 2023; +6 +Table of Contents +• Acreage conducive to drilling longer laterals with an expected average lateral length for operated locations of approximately 9,400 feet; and +• Upside related to potential midstream opportunities for Pronto, which operates in Lea County, New Mexico. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2022, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2022. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +237,100 129,400 1,087 543.3 4,382 1,468 346,788 61.0 100,135 +South Texas: +Eagle Ford (5) +15,400 13,100 91 72.3 124 98 3,861 100.0 1,373 +Northwest Louisiana +Haynesville 16,200 8,900 246 19.1 161 14 5,126 99.0 3,789 +Cotton Valley (6) +15,800 14,900 65 39.8 154 35 947 100.0 168 +Area Total (7) +18,500 17,300 311 58.9 315 49 6,073 99.2 3,957 +Total 271,000 159,800 1,489 674.5 4,821 1,615 356,722 62.1 105,465 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2022. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2022, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2022, these engineered drilling locations included 390 gross (156 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon formations, in the Delaware Basin and only seven gross (less than 0.1 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. At December 31, 2022, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2022. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2022, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2022, we also were the operator for approximately 87% of our Eagle Ford acreage and approximately 51% of our Haynesville acreage. +7 +Table of Contents +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations. +In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2022, our total acreage position in Southeast New Mexico and West Texas was approximately 237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 40,700 gross (22,600 net) acres in our Ranger asset area in Lea County, 59,500 gross (22,500 net) acres in our Arrowhead asset area in Eddy County, 45,500 gross (26,400 net) acres in our Rustler Breaks asset area in Eddy County, 26,500 gross (17,900 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 47,000 gross (25,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2022. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2022, our acreage position in the Delaware Basin was approximately 77% held by existing production. Excluding the Twin Lakes asset area and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 92% held by existing production at December 31, 2022. +During the year ended December 31, 2022, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin, including 81 gross (64.5 net) operated horizontal wells and 63 gross (5.4 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2022, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. +As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2022. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021. +8 +Table of Contents +At December 31, 2022, approximately 97% of our estimated total proved oil and natural gas reserves, or 346.8 million BOE, was attributable to the Delaware Basin, including approximately 193.5 million Bbl of oil and 919.7 Bcf of natural gas, an 11% increase, as compared to 312.0 million BOE for the year ended December 31, 2021. Our Delaware Basin proved reserves at December 31, 2022 comprised approximately 99% of our proved oil reserves and 96% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and 95% of our proved natural gas reserves at December 31, 2021. +At December 31, 2022, we had identified 4,382 gross (1,468 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,198 gross (1,296 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2022, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2022, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2022, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2022, these potential future drilling locations included 390 gross (156 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon and Avalon, to which we have assigned proved undeveloped reserves. +We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. +Antelope Ridge Asset Area - Lea County, New Mexico +In the Antelope Ridge asset area, we turned to sales 26 gross (21.9 net) operated wells and 23 gross (0.6 net) non-operated wells during 2022. +The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. At the end of the first quarter of 2022, we achieved one of our five operational milestones we set for Matador in 2022 when we turned to sales nine gross (8.1 net) wells on the Rodney Robinson leasehold. These wells were the third group of wells drilled on the Rodney Robinson leasehold. The nine Rodney Robinson wells, which included one Third Bone Spring completion, two Second Bone Spring completions, three First Bone Spring completions and three Avalon completions, have produced in aggregate approximately 3.1 million BOE in approximately ten months of production. +In the third and fourth quarter of 2022, we achieved another one of our five operational milestones in 2022 when we turned to sales 16 gross (12.9 net) operated wells in other portions of the Antelope Ridge asset area. In addition, we turned to sales one gross (0.9 net) operated well in the first quarter of 2022. In total, these 17 Antelope Ridge wells, which included three Third Bone Spring, eight Second Bone Spring and six First Bone Spring completions have produced in aggregate approximately 1.8 million BOE in an average of approximately four months of production. +In September 2022, we added a seventh drilling rig, which enabled us to accelerate the timing of the fourth group of eight Rodney Robinson wells. These eight gross (7.7 net) wells are expected to be turned to sales late in the first quarter of 2023. We plan to turn to sales 12 gross (9.1 net) operated wells in the Antelope Ridge asset area in 2023. +Rustler Breaks Asset Area - Eddy County, New Mexico +In the Rustler Breaks asset area, we turned to sales 21 gross (13.5 net) operated wells and 22 gross (2.3 net) non-operated wells during 2022. +9 +Table of Contents +In the second quarter of 2022, we achieved one of our five operational milestones in 2022 when we turned to sales eleven gross (6.5 net) wells in the Rustler Breaks asset area. In addition, we turned to sales an additional ten gross (7.0 net) operated wells at various times in the third and fourth quarters of 2022. In total, these 21 Rustler Breaks wells, which included four Wolfcamp B, two Wolfcamp A, two Third Bone Spring, one Third Bone Spring Carbonate, seven Second Bone Spring, four First Bone Spring and one Brushy Canyon completions, have produced in aggregate approximately 3.8 million BOE in an average of approximately six months of production. +We plan to turn to sales 21 gross (13.2 net) operated wells in the Rustler Breaks asset area in 2023. +Arrowhead Asset Area - Eddy County, New Mexico +In the Arrowhead asset area, we turned to sales two gross (1.1 net) operated wells and eight gross (1.3 net) non-operated wells during 2022. This included two Second Bone Spring completions that turned to sales late in the fourth quarter of 2022. +We plan to turn to sales 18 gross (11.5 net) operated wells in the Arrowhead asset area in 2023. +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales 14 gross (10.1 net) operated wells and ten gross (1.2 net) non-operated wells during 2022. In the Twin Lakes area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2022. +In February 2022, we contracted a sixth drilling rig to begin development on certain properties acquired in the western portion of our Ranger asset area and late in the fourth quarter of 2022, we achieved another one of our five operational milestones for 2022 when we turned to sales 12 gross (8.8 net) wells. This included two Wolfcamp A, four Third Bone Spring, five Second Bone Spring and one First Bone Spring completions, which have in aggregate produced 0.3 million BOE in approximately one month of production. +Early in the first quarter of 2022, we also turned to sales the second batch of two Uncle Ches wells, which targeted the Second Bone Spring Sand. We are very pleased with the results of these additional Uncle Ches wells, which in aggregate, have produced over 0.7 million BOE in 11 months of production and are exhibiting high (90%) oil cuts and low water cuts (approximately one Bbl of water per Bbl of oil produced). +We plan to turn to sales 21 gross (14.5 net) operated wells in the Ranger asset area in 2023, not including any wells expected to be turned to sales on Advance’s properties. +Stateline Asset Area - Eddy County, New Mexico +In the Stateline asset area, we turned to sales 15 gross (15.0 net) operated wells during 2022. Early in the first quarter of 2022, we achieved another one of our five operational milestones in 2022 when we turned to sales 11 gross (11.0 net) wells on the Voni leasehold in the Stateline asset area. The 11 Voni wells, which included four Wolfcamp B, five Third Bone Spring Carbonate and two First Bone Spring completions, have produced in aggregate approximately 3.6 million BOE in approximately 11 months of production. These 11 Voni wells had average completed lateral lengths of approximately 12,100 feet. +In the second quarter of 2022, we returned to Stateline to drill an additional batch of four Wolfcamp B wells on the Boros leasehold on the eastern side of the Stateline asset area. These four Wolfcamp B completions were turned to sales late in the third quarter of 2022 and have produced in aggregate approximately 0.5 million BOE in approximately three months. +We plan to turn to sales eight gross (8.0 net) operated wells in the Stateline asset area in 2023. +Wolf and Jackson Trust Asset Areas - Loving County, Texas +In the Wolf and Jackson Trust asset areas, we turned to sales three gross (2.7 net) operated wells during 2022. This included three Second Bone Spring completions that have in aggregate produced 0.9 million BOE in approximately 11 months. +We plan to turn to sales nine gross (8.3 net) operated wells in the Wolf asset area in 2023 . +South Texas — Eagle Ford Shale and Other Formations +At December 31, 2022, our properties included approximately 15,400 gross (13,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2022. +10 +Table of Contents +During the year ended December 31, 2022, we converted approximately $46.5 million of non-core assets to cash, including the sales of approximately 12,000 gross (12,000 net) acres in the Eagle Ford shale for approximately $46.5 million. We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2022. In fact, as of December 31, 2022, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 35% to 1,373 BOE per day, including 971 Bbl of oil per day and 2.4 MMcf of natural gas per day, during 2022, as compared to 2,126 BOE per day, including 1,528 Bbl of oil per day and 3.6 MMcf of natural gas per day, during 2021. For the year ended December 31, 2022, 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 2% for the year ended December 31, 2021. +At December 31, 2022, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.9 million BOE, was attributable to the Eagle Ford shale, including approximately 2.8 million Bbl of oil and 6.5 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2022, essentially unchanged from December 31, 2021. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated Haynesville shale wells that were turned to sales in 2022. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2023. +At December 31, 2022, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,800 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2022. +For the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or 3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 4% of our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 9% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to these properties. At December 31, 2022, approximately 2% of our estimated total proved reserves, or 6.1 million BOE, was attributable to our properties in Northwest Louisiana. +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 21, 2023, we had earned all of the potential $73.5 million in performance incentives. Through February 21, 2023, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021, and the remaining $14.7 million in performance incentives is expected to be paid during the first quarter of 2023. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +11 +Table of Contents +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through mid-2024 , plus additional performance incentives for securing volumes from third-party customers. At February 21, 2023, we had received $62.2 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2022, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +At December 31, 2022, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2022, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area. +In addition, at December 31, 2022, San Mateo had an NGL pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2022, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2022, San Mateo gathered an average of approximately 287 MMcf of natural gas per day, an increase of 22% as compared to 236 MMcf of natural gas per day gathered during the year ended December 31, 2021. In addition, during the year ended December 31, 2022, San Mateo processed approximately 289 MMcf of natural gas at the Black River Processing Plant, an increase of 36%, as compared to 213 MMcf of natural gas per day processed during the year ended December 31, 2021. Natural gas gathering and processing volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain +12 +Table of Contents +San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. +At December 31, 2022, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and (iii) approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +At December 31, 2022, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2022, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. +At December 31, 2022, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2022, the San Mateo Oil Pipeline Systems had throughput of approximately 48,300 Bbl of oil per day, an increase of 18%, as compared to throughput of approximately 40,800 Bbl of oil per day during the year ended December 31, 2021. +Produced Water Gathering and Disposal Assets +During 2022, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 21, 2023, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 21, 2023, San Mateo had designed disposal capacity of approximately 445,000 Bbl of produced water per day. +During the year ended December 31, 2022, San Mateo handled approximately 361,000 Bbl of produced water per day, an increase of 30%, as compared to approximately 278,000 Bbl of produced water per day handled during the year ended December 31, 2021. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo or Pronto. +13 +Table of Contents +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2022, 2021 and 2020. +Year Ended December 31, +2022 2021 2020 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 21,943 17,840 15,931 +Natural gas (Bcf) 99.3 81.7 69.5 +Total oil equivalent (MBOE) (1) +38,495 31,454 27,514 +Average daily production (BOE/d) (1) +105,465 86,176 75,175 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 96.32 $ 67.58 $ 37.38 +Oil, with realized derivatives (per Bbl) $ 92.87 $ 56.70 $ 39.83 +Natural gas, without realized derivatives (per Mcf) $ 7.98 $ 6.06 $ 2.14 +Natural gas, with realized derivatives (per Mcf) $ 7.15 $ 5.74 $ 2.14 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 7.33 $ 5.69 $ 3.39 +Lease operating $ 4.08 $ 3.46 $ 3.81 +Plant and other midstream services operating $ 2.48 $ 1.95 $ 1.51 +Depletion, depreciation and amortization $ 12.11 $ 10.97 $ 13.15 +General and administrative $ 3.02 $ 3.06 $ 2.27 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 21,585 355 — 3 21,943 +Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3 +Total oil equivalent (MBOE) (3) +36,550 501 1,383 61 38,495 +Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 59,139 971 — 9 60,119 +Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1 +Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465 +Average Sales Prices (4) +Oil (per Bbl) $ 96.34 $ 95.23 $ — $ 91.53 $ 96.32 +Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98 +Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 17,279 558 — 3 17,840 +Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7 +Total oil equivalent (MBOE) (3) +29,395 776 1,217 66 31,454 +Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 47,339 1,528 — 9 48,876 +Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8 +Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176 +Average Sales Prices (4) +Oil (per Bbl) $ 67.65 $ 65.41 $ — $ 64.40 $ 67.58 +Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06 +Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 15,254 674 — 3 15,931 +Natural gas (Bcf) 56.8 1.2 11.0 0.5 69.5 +Total oil equivalent (MBOE) (3) +24,713 883 1,835 83 27,514 +Percentage of total annual net production 89.8 % 3.2 % 6.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 41,678 1,840 — 8 43,526 +Natural gas (MMcf/d) 155.1 3.4 30.1 1.3 189.9 +Total oil equivalent (BOE/d) 67,522 2,412 5,015 226 75,175 +Average Sales Prices (4) +Oil (per Bbl) $ 37.38 $ 37.42 $ 28.77 $ 38.31 $ 37.38 +Natural gas (per Mcf) $ 2.23 $ 2.82 $ 1.66 $ 1.69 $ 2.14 +Total oil equivalent (per BOE) $ 28.19 $ 32.56 $ 9.94 $ 11.09 $ 27.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.52 $ 20.52 $ 4.71 $ 19.39 $ 5.09 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022 increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to 86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was 272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended December 31, 2021. +Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021 increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31, 2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the year ended December 31, 2020. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2022. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 81% in all wells that we operated at December 31, 2022. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +929 461.8 158 81.5 1,087 543.3 +South Texas: +Eagle Ford (2) +91 72.3 — — 91 72.3 +Northwest Louisiana: +Haynesville — — 246 19.1 246 19.1 +Cotton Valley (3) +1 1.0 64 38.8 65 39.8 +Area Total 1 1.0 310 57.9 311 58.9 +Total 1,021 535.1 468 139.4 1,489 674.5 +__________________ +(1) Includes 239 gross (87.5 net) vertical wells that were primarily acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2022, 2021 and 2020. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. +At December 31, (1) +2022 2021 2020 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 196,289 181,306 159,949 +Natural Gas (Bcf) 962.6 852.5 662.3 +Total (MBOE) (3) +356,722 323,397 270,332 +Estimated proved developed reserves: +Oil (MBbl) 116,030 102,233 69,647 +Natural Gas (Bcf) 632.9 546.2 323.2 +Total (MBOE) (3) +221,507 193,262 123,507 +Percent developed 62.1 % 59.8 % 45.7 % +Estimated proved undeveloped reserves: +Oil (MBbl) 80,259 79,073 90,301 +Natural gas (Bcf) 329.7 306.4 339.1 +Total (MBOE) (3) +135,215 130,135 146,825 +Standardized Measure (4) (in millions) +$ 6,983.2 $ 4,375.4 $ 1,584.4 +PV-10 (5) (in millions) +$ 9,132.2 $ 5,347.6 $ 1,658.0 +__________________ +17 +Table of Contents +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas, for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas and for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2022, 2021 and 2020 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2022, 2021 and 2020 were $2.15 billion, $972.2 million and $73.6 million, respectively. +Our estimated total proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. This increase in proved oil and natural gas reserves was primarily attributable to (i) our delineation and development operations in the Delaware Basin during 2022 and (ii) the 43% increase in oil prices and the 77% increase in natural gas prices used to estimate total proved reserves at December 31, 2022, as compared to December 31, 2021. We added 71.1 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations turned to sales during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022, but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 7.4 million BOE to proved reserves at a future date. +Our proved oil reserves grew 8% from approximately 181.3 million Bbl at December 31, 2021 to approximately 196.3 million Bbl at December 31, 2022. Our proved natural gas reserves increased 13% from 852.5 Bcf at December 31, 2021 to 962.6 Bcf at December 31, 2022. Our proved reserves to production ratio at December 31, 2022 was 9.3, a decrease of 10% from 10.3 at December 31, 2021. +The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to December 31, 2021. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2022 were $90.15 per Bbl and $6.36 per MMBtu, an increase of 43% and 77%, respectively, as compared to average oil and natural gas prices of $63.04 per Bbl and $3.60 per MMBtu used to estimate proved reserves at December 31, 2021. Our total proved reserves were made up of 55% oil and 45% natural gas at December 31, 2022 and 56% oil and 44% natural gas at December 31, 2021. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +18 +Table of Contents +The following table summarizes changes in our estimated proved developed reserves at December 31, 2022. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2021 193,262 +Extensions and discoveries 24,717 +Net acquisitions of minerals-in-place 753 +Revisions of prior estimates 2,867 +Production (38,495) +Conversion of proved undeveloped to proved developed 38,403 +As of December 31, 2022 221,507 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 15% from 193.3 million BOE at December 31, 2021 to 221.5 million BOE at December 31, 2022. We added 24.7 million BOE in proved developed reserves through extensions and discoveries during 2022, which resulted from new well locations drilled during 2022 to establish proved reserves. We realized approximately 2.9 million BOE in net upward revisions to prior estimates, most of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2022, which resulted in longer estimated economic lives for certain of our producing properties. In addition, we converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022, primarily in our Ranger, Stateline, Antelope Ridge and Rustler Breaks asset areas. In addition, we realized 0.8 million BOE in net upward revisions to our proved developed reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. These cumulative net upward revisions of 66.7 million BOE to our proved developed reserves exceeded by 1.7 times our total oil and natural gas production of 38.5 million BOE in 2022. +Our proved developed oil reserves increased 13% from 102.2 million Bbl at December 31, 2021 to 116.0 million Bbl at December 31, 2022. Our proved developed natural gas reserves increased 16% from 546.2 Bcf at December 31, 2021 to 632.9 Bcf at December 31, 2022. Proved developed reserves constituted 62% of our total proved oil and natural gas reserves at December 31, 2022, as compared to 60% at December 31, 2021. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2022. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2021 130,135 +Extensions and discoveries 46,388 +Net acquisitions of minerals-in-place 264 +Revisions of prior estimates (3,169) +Conversion of proved undeveloped to proved developed (38,403) +As of December 31, 2022 135,215 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved undeveloped oil and natural gas reserves increased 4% from 130.1 million BOE at December 31, 2021 to 135.2 million at December 31, 2022. We added 53.8 million BOE in proved undeveloped reserves through extensions and discoveries during 2022, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022 but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. We realized approximately 3.2 million BOE in net downward revisions to our prior estimates of proved undeveloped reserves, most of which was attributable to forecast updates at December 31, 2022. In addition, we realized 0.3 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. During 2022, we also converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022. +19 +Table of Contents +At December 31, 2022, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2022 within five years of booking these reserves. The following table sets forth, since 2019, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2019 13,832 58.8 23,629 $ 318,609 +2020 16,256 76.1 28,944 257,590 +2021 23,965 96.6 40,071 240,664 +2022 22,515 95.3 38,403 434,336 +Total 76,568 326.8 131,047 $ 1,251,199 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2022. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 193,500 919.7 346,788 $ 6,852.8 $ 8,961.8 +South Texas: +Eagle Ford (5) +2,780 6.5 3,861 68.4 89.8 +Northwest Louisiana +Haynesville — 30.8 5,126 56.5 73.9 +Cotton Valley (6) +10 5.6 947 5.2 6.8 +Area Total 10 36.4 6,073 61.7 80.7 +Total 196,290 962.6 356,722 $ 6,982.9 $ 9,132.3 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2022 were approximately $2.15 billion. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual +20 +Table of Contents +production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2022. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of our Board of Directors as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2022. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 191,300 99,200 45,800 30,200 237,100 129,400 +South Texas: +Eagle Ford 15,400 13,100 — — 15,400 13,100 +Northwest Louisiana: +Haynesville 16,200 8,900 — — 16,200 8,900 +Cotton Valley 15,800 14,900 — — 15,800 14,900 +Area Total (1) +18,500 17,300 — — 18,500 17,300 +Total 225,200 129,600 45,800 30,200 271,000 159,800 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +21 +Table of Contents +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2022 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2028 and beyond totals 7,100 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2022. +Acres Acres Acres Acres Acres +Expiring 2023 Expiring 2024 Expiring 2025 Expiring 2026 Expiring 2027 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +7,000 4,300 5,300 1,800 8,600 3,700 5,900 2,000 11,600 11,300 +Total 7,000 4,300 5,300 1,800 8,600 3,700 5,900 2,000 11,600 11,300 +__________________ +(1) Approximately 75% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2022, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2022, approximately 1% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2022, 2021 and 2020 . +Year Ended December 31, +2022 2021 2020 +Gross Net Gross Net Gross Net +Development Wells +Productive 138 61.4 96 40.2 89 44.5 +Dry — — — — — — +Exploration Wells +Productive (1) +20 11.0 8 8.0 4 3.3 +Dry — — — — — — +Total Wells +Productive 158 72.4 104 48.2 93 47.8 +Dry — — — — — — +(1) Includes 17 gross (9.4 net) horizontal and three gross (1.6 net) vertical wells. +At December 31, 2022, we had a total of 25 gross (19.4 net) development wells and nine gross (7.8 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and +22 +Table of Contents +natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids, or NGLs, based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include, but are not limited to: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflict between Russia and Ukraine; domestic or global health concerns, including the outbreak of contagious or pandemic diseases such as COVID-19; the continued threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2022, 2021 and 2020, we had three, three and two significant purchasers, respectively, that accounted for approximately 70%, 72% and 65%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to +23 +Table of Contents +expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals. Although some of these restrictions have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +24 +Table of Contents +Environmental +Emissions Mitigation +We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines with expected sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities. +Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control And Data Acquisition (“SCADA”) equipment at a number of larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require. +Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions. +Water Management +Using improving technologies, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. This use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water. +Land Stewardship +We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, which results in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations. +During 2022, 89% of our gross operated oil production and 99% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil, natural gas and water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the produced oil and water. This is significant because it both (i) reduces truck traffic and increases road safety and (ii) reduces emissions. +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +25 +Table of Contents +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states, including Texas, in August 2022. +In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits is uncertain. +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the EPA suggested increasing the value of the social cost of carbon from $51 per metric ton to $190 per metric ton. +In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. +Although some of the restrictions in the Biden Administration Federal Lease Orders lapsed at the end of 2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is +26 +Table of Contents +located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate +27 +Table of Contents +oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The final 2019 gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +Hydraulic Fracturing Policies and Procedures +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage). +28 +Table of Contents +Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures. +The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures to protect the environment and work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. +While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations. +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On December 30, 2022, the +29 +Table of Contents +EPA and the Corps jointly issued a pre-publication of a final rule revising the definition of WOTUS that largely returns to the pre-2015 regulatory regime. The rule will become effective 60 days after publication in the Federal Register. +Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the USFWS under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance of NWPs in 2021. In 2021, the Corps issued a new set of NWPs to replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but elected not to consult with the USFWS. The re-issued NWPs were subject to the same legal challenges based on the lack of a formal ESA consultation, but in September 2022, the U.S. District Court for Montana dismissed the ESA-consultation challenges as moot and dismissed the remainder of the lawsuit without prejudice. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and imposes a fee on greenhouse gas (“GHG”) emissions from certain facilities that exceed specified emissions levels. In addition, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on GHGs from new and existing sources in the oil and natural gas industry. On December 6, 2022, the EPA published a supplemental proposal to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA. On December 23, 2022, the EPA proposed a rule that would enable states to implement more stringent methane emissions standards than the federal guidelines require. Also in November 2022, the BLM proposed a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas +30 +Table of Contents +production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. +In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort is designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent +31 +Table of Contents +seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. +Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On November 25, 2022, a final rule was published that lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. The effective date of the final rule is March 27, 2023. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle +32 +Table of Contents +Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions. +As of December 31, 2022, approximately 31% of our Delaware Basin acreage position consisted of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have a material adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +33 +Table of Contents +Human Capital +At December 31, 2022, we had 360 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2022, for example, our employees completed approximately 16,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2022, we estimate our employees have worked approximately 3.3 million combined hours without experiencing a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations to proactively minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +34 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/item13.txt b/raw/filings/0001520006/2022/0001520006-23-000056/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2022/0001520006-23-000056/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/item9a.txt b/raw/filings/0001520006/2022/0001520006-23-000056/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..0cc7f9ca35c5c4ac75dce36c9783d342a2ebd677 --- /dev/null +++ b/raw/filings/0001520006/2022/0001520006-23-000056/item9a.txt @@ -0,0 +1,29 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2022 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2022, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2022 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +94 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements), and our report dated March 1, 2023 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +March 1, 2023 +95 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/rp_note.txt b/raw/filings/0001520006/2022/0001520006-23-000056/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2022/0001520006-23-000056/rpt_disclosure.txt b/raw/filings/0001520006/2022/0001520006-23-000056/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..3b2a57e4aee2cec5ccba792776f48ba470e226ea --- /dev/null +++ b/raw/filings/0001520006/2022/0001520006-23-000056/rpt_disclosure.txt @@ -0,0 +1,68 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2022, there was not, nor was there proposed as of December 31, 2022, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, nominees for directors, executive officers, beneficial owners of more than 5% of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation—Compensation Discussion and Analysis” and “Director Compensation” above. +Working Interest and Overriding Royalty Interest Owners +Joseph Wm. Foran, Chairman and Chief Executive Officer, Shelley F. Appel, a nominee for director at the 2023 Annual Meeting, and certain of their affiliated entities (collectively, the “Foran Entities”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, the Foran Entities are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Foran Entities are entitled to receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2022, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners or overriding royalty interest owners were approximately $13.2 million (the “Related Net Revenue Payments”). The Related Net Revenue Payments represent less than 1% of our total third-party net revenue payments during 2022. +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2022, our joint interest billings to the Foran Entities attributable to their share of costs were approximately $9.8 million (the “Related Joint Interest Billings”). The Related Joint Interest Billings represent less than 1% of our total joint interest billings during 2022. As a result of this ownership by the Foran Entities, from time to time, we will be in a net receivable or net payable position with certain of the Foran Entities. We do not consider any net receivables from the Foran Entities to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Foran Entities for potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s relationships and interests in such transactions and all other material facts related to the Related Net Revenue Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Joint Venture Relationship +The Company has entered into a joint venture (the “Joint Venture”) with Spearpoint Resources Company (“Spearpoint”) to generate value through a conventional vertical well development program in our Twin Lakes asset area. An adult child of Mr. Foran and the sibling of Ms. Appel is the founder of Spearpoint and serves as the chief executive officer and chairman of the board of directors of Spearpoint. Mr. Foran’s child has a Bachelor of Arts degree in Economics from Princeton University, a Master’s of Science degree in Petroleum Engineering from Texas A&M University and a Master’s degree in Business Administration from Rice University. Mr. Foran’s child worked for a major oil and gas company as a petroleum petrophysicist. Prior to attending Texas A&M, Mr Foran’s child served in the United States Marine Corp, including two tours of duty overseas, and has continued to serve in United State Marine Corp Reserve, recently achieving the rank of Major. Mr. Foran’s child may perform shared services to the Joint Venture, for which the Joint Venture would reimburse Spearpoint. In addition, Ms. Appel holds an ownership interest in Spearpoint. +76 Matador Resources Company | 2023 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +During 2022, the Company made capital contributions to the Joint Venture of approximately $9.5 million (the “Capital Contributions”). The Company did not receive any distributions from the Joint Venture in 2022, and the Joint Venture did not pay Spearpoint for any shared services provided by Mr. Foran’s child, although such distributions may be received by the Company or such shared service amounts may be paid by Spearpoint in the future. +The Audit Committee reviewed the terms of the Joint Venture for potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s and his adult child’s relationships and interests in such transactions and all other material facts related to the Joint Venture, determined that such transactions, including the Capital Contributions, were fair to the Company and recommended such transactions to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions, including the Capital Contributions. +Certain Employment Relationships +Billy E. Goodwin served as an executive officer during 2022 and currently serves as the Company’s President – Operations. During 2022, an adult child of Mr. Goodwin was an employee of the Company and has been an employee since 2015. Mr. Goodwin’s child earned in 2022 and is expected to be compensated in 2023 between $120,000 and $500,000. Mr. Goodwin’s child has a Bachelor of Science in Business Administration degree in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He has over 12 years of industry experience, including as a drilling fluids engineer for a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Goodwin’s adult child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s sister-in-law has been an employee of the Company since 2016 and earned in 2022, and is expected to be compensated in 2023, between $120,000 and $250,000. Mr. Baribault’s sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist University Legal Assistants Program. She has over 40 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of Mr. Foran and the sibling of Ms. Appel, has been an employee of the Company since 2015 and earned in 2022, and is expected to be compensated in 2023, between $120,000 and $250,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than 11 years of industry experience, including with another publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Foran’s child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +In addition, Ms. Appel, who is a nominee for director at the 2023 Annual Meeting and is the daughter of Mr. Foran, served as the Company’s Environmental, Social and Governance Coordinator and as a Special Advisor to the Board in 2022. For these services, Ms. Appel was compensated between $120,000 and $250,000. Ms. Appel has a degree from Yale University and a Master’s degree in Business Administration from the University of Chicago +2023 Proxy Statement | Matador Resources Company 77 +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +and also worked for a major oil and gas company for a number of years. For further details of Ms. Appel’s relationship with the Company and her background and experience, please see her biography on page 16 of this Proxy Statement. The Audit Committee reviewed the terms of the employment arrangement and the consulting arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and the consulting arrangement and historical and anticipated compensation of Ms. Appel, and all other material facts related to the relationship, determined that the employment arrangement and the consulting arrangement each was fair to the Company and recommended the employment arrangement and the consulting arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement and such consulting arrangement. +Indemnification Agreements +We have entered into indemnification agreements with each of our directors and executive officers and expect to do so in the future for any new directors and executive officers. The indemnification agreements provide the directors and executive officers with contractual rights to indemnification, expense advancement and reimbursement to the fullest extent permitted by applicable law. +Procedures for Approval of Related Person Transactions +Pursuant to the Related Person Transaction Policy as in effect as of December 31, 2022, a “Related Person Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, in which a Related Person (as defined below) has or will have a direct or indirect material interest and in which we are a participant, other than: +• +a transaction involving compensation of directors that is required to be reported in our proxy statement under Item 402 of the SEC’s compensation disclosure requirements (“Item 402”); +• +any employment by us of an executive officer if: +¡ +the related compensation is required to be reported in our proxy statement under Item 402; or +¡ +the executive officer is not an “immediate family member” of another executive officer or director of the Company, the related compensation would be reported in our proxy statement under Item 402 if the executive officer was a “named executive officer” and the Compensation Committee approved (or recommended that the Board approve) such compensation; +• +a transaction with a Related Person involving less than $120,000; +• +a transaction in which the interest of the Related Person arises solely from the ownership of a class of our equity securities and all holders of that class receive the same benefit on a pro rata basis; +• +a transaction in which a Related Person has an indirect interest solely as a result of being (a) a director or, together with all other Related Persons, a less than 10% beneficial owner of an equity interest in another entity, or both, or (b) a limited partner in a partnership in which the Related Person, together with all other Related Persons, has an interest of less than 10%; +• +a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority; +• +any transaction with another company at which a Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the greater of $1,000,000, or 2% of that company’s total annual revenues; +• +any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the lesser of $1,000,000, or 2% of the charitable organization’s total annual receipts; +78 Matador Resources Company | 2023 Proxy Statement +Table of Contents +TRANSACTIONS WITH RELATED PERSONS +• +any transaction with another publicly traded company where the Related Person’s interest arises solely from beneficial ownership of more than 5% of our Common Stock and ownership of a non-controlling interest in the other publicly traded company; +• +reimbursement of business expenses incurred by a director, officer or employee of the Company in the performance of his or her duties and approved for reimbursement by the Company in accordance with the Company’s customary policies and practices; or +• +indemnification and advancement of expenses made pursuant to the Certificate of Formation or the Bylaws or pursuant to any agreement. +“Related Person” means: +• +any person who is, or at any time since the beginning of the Company’s last completed fiscal year was, one of our executive officers or one of our directors or nominees for director; +• +any person (including any entity or group) who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• +any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law or person residing (other than a tenant or employee) in the home of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• +any entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Person Transaction Policy, the Audit Committee must review all material facts of each Related Person Transaction and recommend either approval or disapproval of the Related Person Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Person Transaction, the Audit Committee must, after reviewing all material facts of the Related Person Transaction and the Related Person’s relationship and interest, determine whether the Related Person Transaction is fair to the Company and in, or not consistent with, the interests of the Company and its shareholders. If a Related Person Transaction will be ongoing, the Audit Committee, on at least an annual basis, will review and assess ongoing relationships with the Related Persons to see that they are in compliance with Audit Committee guidelines. Further, the policy requires that all Related Person Transactions be disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +2023 Proxy Statement | Matador Resources Company 79 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/filing.txt b/raw/filings/0001520006/2023/0001520006-24-000078/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e831fc06f80ef5b4982eafb097956dc4d599700b --- /dev/null +++ b/raw/filings/0001520006/2023/0001520006-24-000078/filing.txt @@ -0,0 +1,3342 @@ +mtdr-20231231 +0001520006 false 2023 FY P5Y P1M http://fasb.org/us-gaap/2023#OtherAssetsNoncurrent http://fasb.org/us-gaap/2023#OtherAssetsNoncurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2023#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2023#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2023#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2023#OtherLiabilitiesNoncurrent P1M P3M http://fasb.org/us-gaap/2023#OtherAssetsNoncurrent http://fasb.org/us-gaap/2023#OtherReceivablesNetCurrent http://fasb.org/us-gaap/2023#OtherAssetsNoncurrent http://fasb.org/us-gaap/2023#OtherReceivablesNetCurrent 0001520006 2023-01-01 2023-12-31 0001520006 2023-06-30 iso4217:USD 0001520006 2024-02-20 xbrli:shares 0001520006 2023-10-01 2023-12-31 0001520006 2023-12-31 0001520006 2022-12-31 iso4217:USD xbrli:shares 0001520006 us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2023-01-01 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember 2023-01-01 2023-12-31 0001520006 mtdr:NaturalGasSalesMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember 2021-01-01 2021-12-31 0001520006 2022-01-01 2022-12-31 0001520006 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2020-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2020-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2020-12-31 0001520006 us-gaap:ParentMember 2020-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2020-12-31 0001520006 2020-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-01-01 2021-12-31 0001520006 us-gaap:ParentMember 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-01-01 2021-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2021-01-01 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-01-01 2021-12-31 0001520006 us-gaap:CommonStockMember 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2021-12-31 0001520006 us-gaap:ParentMember 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-12-31 0001520006 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2022-01-01 2022-12-31 0001520006 us-gaap:ParentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2022-01-01 2022-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2022-01-01 2022-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2022-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2022-12-31 0001520006 us-gaap:RetainedEarningsMember 2022-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2022-12-31 0001520006 us-gaap:ParentMember 2022-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2022-12-31 0001520006 us-gaap:RetainedEarningsMember 2023-01-01 2023-12-31 0001520006 us-gaap:ParentMember 2023-01-01 2023-12-31 0001520006 us-gaap:CommonStockMember 2023-01-01 2023-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2023-01-01 2023-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2023-01-01 2023-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2023-01-01 2023-12-31 0001520006 us-gaap:CommonStockMember 2023-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2023-12-31 0001520006 us-gaap:RetainedEarningsMember 2023-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2023-12-31 0001520006 us-gaap:ParentMember 2023-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2023-12-31 0001520006 mtdr:AdvanceMember 2023-01-01 2023-12-31 0001520006 mtdr:AdvanceMember 2022-01-01 2022-12-31 0001520006 mtdr:AdvanceMember 2021-01-01 2021-12-31 0001520006 mtdr:MidstreamMember 2023-01-01 2023-12-31 0001520006 mtdr:MidstreamMember 2022-01-01 2022-12-31 0001520006 mtdr:MidstreamMember 2021-01-01 2021-12-31 0001520006 srt:MinimumMember 2023-01-01 2023-12-31 0001520006 srt:MaximumMember 2023-01-01 2023-12-31 mtdr:purchaser 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 xbrli:pure 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember mtdr:PlainsMarketingL.P.Member 2023-01-01 2023-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 0001520006 mtdr:EnterpriseMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember mtdr:PlainsMarketingL.P.Member 2022-01-01 2022-12-31 0001520006 mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2021-01-01 2021-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2021-01-01 2021-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember mtdr:PlainsMarketingL.P.Member 2021-01-01 2021-12-31 0001520006 mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2021-01-01 2021-12-31 0001520006 us-gaap:CustomerConcentrationRiskMember mtdr:PlainsMarketingL.P.Member us-gaap:AccountsReceivableMember 2023-01-01 2023-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2022-01-01 2022-12-31 0001520006 mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2021-01-01 2021-12-31 iso4217:USD utr:bbl iso4217:USD utr:MMBTU 0001520006 us-gaap:MachineryAndEquipmentMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember us-gaap:MachineryAndEquipmentMember 2023-12-31 0001520006 us-gaap:MachineryAndEquipmentMember srt:MaximumMember 2023-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2021-01-01 2021-12-31 0001520006 srt:OilReservesMember 2023-01-01 2023-12-31 0001520006 srt:OilReservesMember 2022-01-01 2022-12-31 0001520006 srt:OilReservesMember 2021-01-01 2021-12-31 0001520006 srt:NaturalGasReservesMember 2023-01-01 2023-12-31 0001520006 srt:NaturalGasReservesMember 2022-01-01 2022-12-31 0001520006 srt:NaturalGasReservesMember 2021-01-01 2021-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2023-12-31 0001520006 us-gaap:SupportEquipmentAndFacilitiesMember 2022-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2023-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2022-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2023-12-31 0001520006 us-gaap:ComputerSoftwareIntangibleAssetMember 2022-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2023-12-31 0001520006 us-gaap:LeaseholdsAndLeaseholdImprovementsMember 2022-12-31 0001520006 mtdr:CurrentYearMember 2023-12-31 0001520006 mtdr:PriorYearMember 2023-12-31 0001520006 mtdr:TwoYearsPriorMember 2023-12-31 0001520006 mtdr:ThreeYearsPriorMember 2023-12-31 0001520006 mtdr:ThreeYearsandPriorMember 2023-12-31 0001520006 mtdr:ProjectsInceptiontoDateMember 2023-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2023-01-01 2023-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasServiceMember 2023-01-01 2023-12-31 0001520006 us-gaap:OilAndGasServiceMember 2022-01-01 2022-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2023-01-01 2023-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2022-01-01 2022-12-31 0001520006 mtdr:DrillingRigLeasesMember 2023-01-01 2023-12-31 0001520006 mtdr:DrillingRigLeasesMember 2022-01-01 2022-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2023-01-01 2023-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2022-01-01 2022-12-31 0001520006 mtdr:AdvanceMember 2023-04-12 2023-04-12 0001520006 mtdr:AdvanceMember 2023-04-12 0001520006 mtdr:AdvanceMember 2023-01-01 2023-03-31 0001520006 mtdr:AdvanceMember 2023-07-01 2023-09-30 0001520006 mtdr:AdvanceMember 2023-04-01 2023-06-30 0001520006 mtdr:AdvanceMember 2023-10-01 2023-12-31 0001520006 mtdr:AdvanceORRIAcquisitionMember 2023-10-01 2023-10-01 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-10-01 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-04-12 2023-04-12 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-04-12 0001520006 us-gaap:OilAndGasMember mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-04-12 2023-12-31 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-01-01 2023-12-31 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2022-01-01 2022-12-31 0001520006 mtdr:SummitMidstreamMember 2022-06-30 mtdr:compressor_station utr:mi 0001520006 mtdr:SummitMidstreamMember 2022-06-30 2022-06-30 0001520006 mtdr:SummitMidstreamMember 2022-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2023-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2028Member 2023-12-31 0001520006 us-gaap:LetterOfCreditMember mtdr:CreditAgreementMember 2023-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2023-12-31 0001520006 mtdr:FourthAmendedCreditAgreementMember us-gaap:LineOfCreditMember 2021-11-18 2021-11-18 0001520006 mtdr:FourthAmendedCreditAgreementMember us-gaap:LineOfCreditMember 2021-11-18 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:AmendmentToCreditAgreementMarch2023Member 2023-03-31 0001520006 us-gaap:RevolvingCreditFacilityMember mtdr:AmendmentToCreditAgreementOctober2023Member 2023-10-31 0001520006 us-gaap:LetterOfCreditMember mtdr:CreditAgreementMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:EurodollarMember 2023-01-01 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MaximumMember us-gaap:EurodollarMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember mtdr:BaseRateLoanMember 2023-01-01 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember mtdr:BaseRateLoanMember srt:MaximumMember 2023-01-01 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2023-01-01 2023-12-31 0001520006 mtdr:InterestPeriodOneMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2023-01-01 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember mtdr:InterestPeriodTwoMember 2023-01-01 2023-12-31 0001520006 mtdr:InterestPeriodThreeMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember mtdr:ThirdAmendedCreditAgreementMember 2023-01-01 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MaximumMember 2023-01-01 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2023-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2023-01-01 2023-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2018-12-19 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2023-10-31 0001520006 mtdr:SanMateoCreditFacilityMember 2023-12-31 0001520006 us-gaap:LineOfCreditMember us-gaap:FederalFundsEffectiveSwapRateMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:AdjustedLIBORateMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember us-gaap:LineOfCreditMember mtdr:AdjustedLIBORateMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:AdjustedLIBORateMember srt:MaximumMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember mtdr:StatutoryReserveRateMember 2023-01-01 2023-12-31 0001520006 us-gaap:LineOfCreditMember srt:MaximumMember mtdr:SanMateoCreditFacilityMember mtdr:StatutoryReserveRateMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 us-gaap:LineOfCreditMember srt:MaximumMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 mtdr:TheBankOfNovaScotiaMember mtdr:SanMateoCreditFacilityMember 2023-01-01 2023-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-01-01 2023-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:DebtInstrumentRedemptionPeriodTwoMember us-gaap:UnsecuredDebtMember 2023-01-01 2023-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:Additional2026NotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-01-01 2023-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:Additional2026NotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2028Member us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-04-11 2023-04-11 0001520006 us-gaap:DebtInstrumentRedemptionPeriodTwoMember us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2028Member 2023-04-11 2023-04-11 0001520006 us-gaap:SeniorNotesMember mtdr:SeniorNotesDue2028Member us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-01-01 2023-12-31 0001520006 us-gaap:DebtInstrumentRedemptionPeriodTwoMember us-gaap:SeniorNotesMember mtdr:SeniorNotesDue2028Member 2023-01-01 2023-12-31 0001520006 us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodThreeMember mtdr:SeniorNotesDue2028Member 2023-01-01 2023-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2028Member us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-01-01 2023-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2028Member us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-12-31 0001520006 us-gaap:LetterOfCreditMember mtdr:CreditAgreementMember 2022-12-31 0001520006 us-gaap:LineOfCreditMember mtdr:SanMateoCreditFacilityMember 2022-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2022-12-31 0001520006 us-gaap:UnsecuredDebtMember mtdr:SeniorNotesDue2028Member 2022-12-31 0001520006 stpr:TX 2023-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2023-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2023-01-01 2023-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2023-12-31 0001520006 us-gaap:EmployeeStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:EmployeeStockMember 2023-12-31 0001520006 srt:MinimumMember mtdr:RestrictedStockServiceBasedMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember srt:MaximumMember 2023-01-01 2023-12-31 0001520006 srt:MinimumMember mtdr:PerformanceBasedStockUnitsMember 2023-01-01 2023-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember srt:MaximumMember 2023-01-01 2023-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2023-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember srt:MaximumMember 2023-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2022-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2022-01-01 2022-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2021-01-01 2021-12-31 0001520006 us-gaap:RestrictedStockMember 2023-12-31 0001520006 us-gaap:RestrictedStockMember 2023-01-01 2023-12-31 0001520006 us-gaap:RestrictedStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:RestrictedStockMember 2021-01-01 2021-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2023-01-01 2023-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2022-01-01 2022-12-31 0001520006 us-gaap:EmployeeStockOptionMember 2021-01-01 2021-12-31 0001520006 2023-04-01 2023-06-30 0001520006 2023-01-01 2023-03-31 0001520006 2023-07-01 2023-09-30 0001520006 2023-03-09 2023-03-09 0001520006 2023-06-01 2023-06-01 0001520006 2023-09-01 2023-09-01 0001520006 2023-10-01 2023-10-31 0001520006 2023-12-01 2023-12-01 0001520006 2022-01-01 2022-03-31 0001520006 2022-04-01 2022-06-30 0001520006 2022-10-01 2022-12-31 0001520006 2022-07-01 2022-09-30 0001520006 us-gaap:SubsequentEventMember 2024-02-13 2024-02-13 0001520006 mtdr:SanMateoMidstreamMember 2023-01-01 2023-12-31 0001520006 mtdr:SanMateoMidstreamMember 2022-01-01 2022-12-31 0001520006 mtdr:SanMateoMidstreamMember 2021-01-01 2021-12-31 0001520006 mtdr:SanMateoMember mtdr:MatadorResourcesCompanyMember 2023-01-01 2023-12-31 0001520006 mtdr:SanMateoMember mtdr:FivePointMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2017-01-01 2017-12-31 0001520006 us-gaap:CorporateJointVentureMember us-gaap:SubsequentEventMember mtdr:SanMateoMidstreamMember 2024-02-20 2024-02-20 0001520006 us-gaap:CorporateJointVentureMember mtdr:FivePointMember mtdr:SanMateoMidstreamMember 2018-01-01 2018-03-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:FivePointMember mtdr:SanMateoMidstreamMember 2020-01-01 2020-03-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:FivePointMember mtdr:SanMateoMidstreamMember 2019-01-01 2019-03-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:FivePointMember mtdr:SanMateoMidstreamMember 2021-01-01 2021-03-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2019-01-01 2019-01-01 0001520006 us-gaap:CorporateJointVentureMember mtdr:FivePointMember mtdr:SanMateoMidstreamMember 2023-01-01 2023-12-31 0001520006 mtdr:FivePointMember 2023-01-01 2023-12-31 0001520006 mtdr:FivePointMember 2022-01-01 2022-12-31 0001520006 mtdr:DerivativeContractCalculationPeriodOneMember mtdr:OilBasisSwapMember 2023-12-31 utr:bbl 0001520006 us-gaap:OtherCurrentAssetsMember 2023-12-31 0001520006 us-gaap:OtherNoncurrentAssetsMember 2023-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2023-01-01 2023-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2022-01-01 2022-12-31 0001520006 srt:OilReservesMember mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 mtdr:RevenuesMember srt:NaturalGasReservesMember 2023-01-01 2023-12-31 0001520006 mtdr:RevenuesMember srt:NaturalGasReservesMember 2022-01-01 2022-12-31 0001520006 mtdr:RevenuesMember srt:NaturalGasReservesMember 2021-01-01 2021-12-31 0001520006 mtdr:RevenuesMember 2023-01-01 2023-12-31 0001520006 mtdr:RevenuesMember 2022-01-01 2022-12-31 0001520006 mtdr:RevenuesMember 2021-01-01 2021-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel1Member 2023-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2023-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel1Member 2022-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2022-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2022-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2022-12-31 0001520006 us-gaap:PipelinesMember 2023-01-01 2023-12-31 0001520006 us-gaap:PipelinesMember 2022-01-01 2022-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2023-01-01 2023-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2022-01-01 2022-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2023-12-31 0001520006 mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember mtdr:SanMateoMidstreamMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateJointVentureMember mtdr:SanMateoMidstreamMember 2023-12-31 0001520006 mtdr:DrillingRigCommitmentsMember 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2023-12-31 utr:MMcf 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2023-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2022-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2023-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2022-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2023-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2022-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2023-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2022-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2023-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2022-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2023-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2022-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2023-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2022-12-31 mtdr:segment 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2023-01-01 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2023-01-01 2023-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2023-01-01 2023-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2023-01-01 2023-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2023-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:ExplorationandProductionSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember 2021-01-01 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2021-01-01 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:NaturalGasMidstreamMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:NaturalGasSalesMember us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-01-01 2021-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-01-01 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2021-01-01 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2021-01-01 2021-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2021-12-31 0001520006 mtdr:MidstreamSegmentMember us-gaap:OperatingSegmentsMember 2021-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2021-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2021-12-31 0001520006 mtdr:OilAndNaturalGasProducingPropertiesAndUndevelopedAcreageInLeaCountyNewMexicoMember us-gaap:SubsequentEventMember 2024-02-15 2024-02-15 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31 , 2023 +or +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-35410 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas 27-4662601 +(State or other jurisdiction of +incorporation or organization) (I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 75240 +Dallas, Texas +(Address of principal executive offices) (Zip Code) +( 972 ) 371-5200 +(Registrant’s telephone number, including area code) +_________________________________________________________ +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Trading symbol(s) Name of each exchange on which registered +Common Stock, par value $0.01 per share MTDR New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ☒ No ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ☐ No ☒ +If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements +of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ +Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $ 5,764,468,069 . +As of February 20, 2024, there were 119,519,883 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2024 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Auditor Name: KPMG LLP +Auditor Location: Dallas, TX +Auditor Firm ID: 185 +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2023 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +35 +I TEM 1B. +Unresolved Staff Comments +67 +I TEM 1C. +Cybersecurity +67 +I TEM 2. +Properties +68 +I TEM 3. +Legal Proceedings +69 +I TEM 4. +Mine Safety Disclosures +69 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +70 +I TEM 6. +Selected Financial Data +73 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +73 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +92 +I TEM 8. +Financial Statements and Supplementary Data +93 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +93 +I TEM 9A. +Controls and Procedures +93 +I TEM 9B. +Other Information +96 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +96 +I TEM 11. +Executive Compensation +96 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +96 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +96 +I TEM 14. +Principal Accounting Fees and Services +96 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +97 +ITEM 16. +Form 10-K Summary +97 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and NGLs; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; the operating results of and availability of any potential distributions from our joint ventures; weather and environmental conditions; disruption from our acquisitions making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions; the risk of litigation and/or regulatory actions related to our acquisitions; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• our business strategy; +• our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized; +• our cash flows and liquidity; +• the amount, timing and payment of dividends, if any; +• our financial strategy, budget, projections and operating results; +• the supply and demand of oil, natural gas and NGLs; +• oil, natural gas and NGL prices, including our realized prices thereof; +• the timing and amount of future production of oil and natural gas; +• the availability of drilling and production equipment; +• the availability of oil storage capacity; +• the availability of oil field labor; +• the amount, nature and timing of capital expenditures, including future exploration and development costs; +• the availability and terms of capital; +• our drilling of wells; +• our ability to negotiate and consummate acquisition and divestiture opportunities; +• the integration of acquisitions with our business; +• government regulation and taxation of the oil and natural gas industry; +• our marketing of oil and natural gas; +• our exploitation projects or property acquisitions; +• the ability of our midstream business to construct, maintain and operate midstream pipelines and facilities, including the operation of cryogenic natural gas processing plants and the drilling of additional salt water disposal wells; +• the ability of our midstream business to attract third-party volumes; +• our costs of exploiting and developing our properties and conducting other operations; +• general economic conditions; +• competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• the effectiveness of our risk management and hedging activities; +• our technology; +• environmental liabilities; +• our initiatives and efforts relating to environmental, social and governance matters; +1 +Table of Contents +• counterparty credit risk; +• geopolitical instability and developments in oil-producing and natural gas-producing countries; +• our future operating results; +• the impact of the Inflation Reduction Act of 2022; and +• our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (iv) references to the “Initial Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, (v) references to the “Advance Royalty Acquisition” refer to the acquisition of additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition, (vi) references to the “Advance Acquisition” refer, collectively, to the Initial Advance Acquisition and the Advance Royalty Acquisition, (vii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries, (viii) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary, and (ix) references to the “Pronto Acquisition” refer to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +2 +Table of Contents +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Pronto; +• maintain our financial discipline; +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +The successful execution of our business strategies, including the Advance Acquisition, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2023. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down some of the borrowings that funded the Advance Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC (“Five Point”), our joint venture partner in San Mateo. Further, we completed several important financing transactions in 2023, including the issuance of the 2028 Notes (as defined below), increasing the elected borrowing commitment and the borrowing base under our Credit Agreement (as defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved important milestones in 2023, including the addition of produced water disposal capacity and being awarded new customer contracts. These actions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2023 Highlights +Advance Acquisition +On April 12, 2023, we completed the Initial Advance Acquisition, pursuant to which our wholly-owned subsidiary acquired Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas. The Initial Advance Acquisition had an effective date of January 1, 2023 and an aggregate purchase price consisting of (i) an amount in cash equal to approximately $1.60 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $7.5 million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $85 per barrel (all such payments for the 12 months in 2023, the “Contingent Consideration”). The Cash Consideration was paid upon the closing of the Initial Advance Acquisition and was funded by a combination of cash on hand and borrowings under the Credit Agreement. We made no payments related to the Contingent Consideration during the first, second or third quarters of 2023. In the fourth quarter of 2023, we paid Contingent Consideration of $15.0 million, as the average oil price for the months of September and October 2023 exceeded $85 per barrel. +On December 1, 2023, we completed the Advance Royalty Acquisition, pursuant to which we acquired additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition. The Advance Royalty Acquisition had an effective date of October 1, 2023 with an aggregate purchase price of approximately $81.0 million (which amount is subject to certain customary post-closing adjustments) and was funded by cash on hand. +The results of operations for the Initial Advance Acquisition and the Advance Royalty Acquisition since the respective closing dates have been included in our consolidated financial statements for the year ended December 31, 2023. The oil and natural gas production from the Advance Acquisition increased our revenues and net income for the period from April 12, 2023 through December 31, 2023 by $398.9 million and $166.9 million, respectively. See Note 5 to the consolidated financial +3 +Table of Contents +statements in this Annual Report for more information regarding the Advance Acquisition. Such information is incorporated herein by reference. +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2023, we achieved record oil, natural gas and average daily oil equivalent production. In 2023, we produced 27.5 million Bbl of oil, an increase of 26%, as compared to 21.9 million Bbl of oil produced in 2022. We also produced 123.4 Bcf of natural gas, an increase of 24% from 99.3 Bcf of natural gas produced in 2022. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022. The increase in oil and natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2023 and 2022. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, an increase of 29% from 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, at December 31, 2022. The Standardized Measure of our total proved oil and natural gas reserves decreased 12% from $6.98 billion at December 31, 2022 to $6.11 billion at December 31, 2023. The PV-10 of our total proved oil and natural gas reserves decreased 16% from $9.13 billion at December 31, 2022 to $7.70 billion at December 31, 2023. The decreases in our Standardized Measure and PV-10 were primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2023, as compared to December 31, 2022, partially offset by a 29% increase in our total proved oil and natural gas reserves at December 31, 2023, as compared to December 31, 2022. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2023, estimated proved developed reserves included 161.6 million Bbl of oil and 782.7 Bcf of natural gas, and estimated proved undeveloped reserves included 110.6 million Bbl of oil and 344.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 63% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2023. Proved developed reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas reserves at December 31, 2022. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2024. +We completed and began producing oil and natural gas from 222 gross (99.6 net) horizontal wells in the Delaware Basin in 2023, including 119 gross (94.0 net) operated and 103 gross (5.6 net) non-operated wells. At December 31, 2023, our total acreage position in the Delaware Basin was approximately 265,600 gross (152,200 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving and Ward Counties, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving and Ward Counties, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 27% to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023, as compared to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022. We expect our Delaware Basin production to increase in 2024 as we continue the delineation and development of these asset areas. +During 2023, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +4 +Table of Contents +• eight Rodney Robinson wells in the first half of 2023; +• eight Stateline wells in the first half of 2023; +• 21 Ranger wells on properties acquired in the Advance Acquisition in the second half of 2023, which was the largest single batch development project in our history; +• 17 Stebbins wells in the second half of 2023; and +• 13 Wolf wells in the second half of 2023, including our first two “U-Turn” two-mile lateral wells. +In addition to achieving these five key operational milestones, other operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2023 included: +• continued drilling of longer laterals, with average completed lateral length for operated wells turned to sales in 2023 of approximately 9,800 feet; and +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2023 of $1.16 billion, which was below our estimated range for 2023 D/C/E capital expenditures of $1.18 to $1.32 billion as provided on February 21, 2023, and was in the middle of the revised estimated range of $1.10 to $1.22 billion, as provided on July 25, 2023. +Capital Resources and Financing Highlights +During 2023, we achieved several significant and important capital resources objectives, which included: +• the generation of free cash flow in all four quarters of 2023; +• the amendment of our dividend policy in the fourth quarter of 2023, pursuant to which we increased the quarterly cash dividend from $0.15 per share of common stock to $0.20 per share of common stock; and +• the receipt of $38.2 million in performance incentives directly from Five Point. +In addition, we completed several important financing transactions in 2023 that increased our operational flexibility, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the issuance of $500.0 million in aggregate principal amount of 6.875% senior notes due 2028 (the “2028 Notes”); +• the spring and fall redetermination under our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.50 billion, as compared to $2.25 billion at December 31, 2022, (ii) increase the elected borrowing commitment to $1.325 billion, as compared to $775.0 million at December 31, 2022, (iii) increase the maximum facility amount to $2.00 billion, as compared to $1.50 billion at December 31, 2022 and (iv) add two new banks to our lending group; and +• the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in October 2023 to (i) increase the lender commitments from $485.0 million to $535.0 million and (ii) add a new bank to San Mateo’s lending group. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point, and through Pronto, which is our wholly-owned subsidiary. +San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. Volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2023 and 2022. +During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. +5 +Table of Contents +At December 31, 2023, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); +• Oil Assets : three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included a cryogenic natural gas processing plant with a designed inlet processing capacity of 60 MMcf per day (the “Marlan Processing Plant”), three compressor stations and approximately 70 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico, spanning from the northeastern portion of the Arrowhead asset area into the Ranger asset area. Pronto has also contracted to construct an additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities to be located near the Marlan Processing Plant. +Environmental, Social and Governance (“ESG”) Initiatives +We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and highest applicable regulatory and legal standards. More recently, we have begun formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB). +Highlights from our ESG initiatives, which generally relate to our operations in 2022 except as otherwise noted, include: +• decreased direct greenhouse gas emissions intensity by 44% in 2022, as compared to 2019; +• decreased methane emissions intensity by 61% in 2022, as compared to 2019; +• decreased flaring intensity by 84% in 2022, as compared to 2019; +• increased use of non-fresh water to 99% of total water consumption in 2022; +• increased number of wells utilizing recycled produced water to 72% of total wells completed in 2022, as compared to 16% in 2019; +• transported 98% of operated produced water and 94% of operated produced oil by pipeline in 2023; and +• provided approximately 22,000 hours of employee continuing education, equating to approximately 59 hours per employee in 2023. +These sustainability metrics have been calculated using the best information available to us. The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2023 data from our ESG initiatives in the second half of 2024 in connection with the preparation of our 2023 Sustainability Report. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2023, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +6 +Table of Contents +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2023. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +265,600 152,200 1,475 756.2 4,640 1,627 452,616 63.0 126,720 +South Texas: +Eagle Ford (5) +14,400 12,100 89 72.1 114 88 3,048 100.0 1,068 +Northwest Louisiana +Haynesville 16,200 8,900 256 18.1 138 13 3,847 100.0 3,761 +Cotton Valley (6) +15,700 14,800 66 39.0 148 35 559 100.0 264 +Area Total (7) +18,500 17,300 322 57.1 286 48 4,406 100.0 4,025 +Total 298,500 181,600 1,886 885.4 5,040 1,762 460,070 63.5 131,813 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2023. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2023, approximately two-thirds of these identified drilling locations in the Delaware Basin were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 83% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2023, these engineered drilling locations included 470 gross (206 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Yeso and Avalon formations, in the Delaware Basin. At December 31, 2023, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale or in Northwest Louisiana. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2023. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2023, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2023, we also operated approximately 90% of our Eagle Ford acreage and approximately 51% of our Haynesville acreage. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin had focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology has enhanced the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations. +7 +Table of Contents +In the western part of the Permian Basin, also known as the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2023, our total acreage position in Southeast New Mexico and West Texas was approximately 265,600 gross (152,200 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving and Ward Counties, Texas. These acreage totals included approximately 62,500 gross (36,200 net) acres in our Ranger asset area in Lea County, 58,000 gross (23,300 net) acres in our Arrowhead asset area in Eddy County, 45,700 gross (26,100 net) acres in our Rustler Breaks asset area in Eddy County, 31,900 gross (21,100 net) acres in our Antelope Ridge asset area in Lea County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County, 42,900 gross (27,100 net) acres in our Twin Lakes asset area in Lea County and 21,200 gross (15,000 net) acres in our Wolf, Jackson Trust and Quito asset areas in Loving and Ward County (collectively “West Texas”) at December 31, 2023. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka, Yeso and Morrow formations. At December 31, 2023, our acreage position in the Delaware Basin was approximately 78% held by existing production. Excluding the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, and the Twin Lakes asset area, our acreage position in the Delaware Basin was approximately 96% held by existing production at December 31, 2023. +During the year ended December 31, 2023, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 222 gross (99.6 net) horizontal wells in the Delaware Basin, including 119 gross (94.0 net) operated horizontal wells and 103 gross (5.6 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2023, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow. +As a result of our ongoing drilling and completion operations in these asset areas and the Advance Acquisition, our Delaware Basin production increased significantly in 2023. Our average daily oil equivalent production from the Delaware Basin increased approximately 27% to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023, as compared to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022. +At December 31, 2023, approximately 98% of our estimated total proved oil and natural gas reserves, or 452.6 million BOE, was attributable to the Delaware Basin, including approximately 270.1 million Bbl of oil and 1.09 Tcf of natural gas, a 31% increase, as compared to 346.8 million BOE for the year ended December 31, 2022. Our Delaware Basin proved reserves at December 31, 2023 comprised approximately 99% of our proved oil reserves and 97% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 96% of our proved natural gas reserves at December 31, 2022. +At December 31, 2023, we had identified 4,640 gross (1,627 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,287 gross (1,437 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2023, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 83% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2023, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2023, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage +8 +Table of Contents +further, we anticipate that we may identify additional locations for future drilling. At December 31, 2023, these potential future drilling locations included 470 gross (206 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Yeso and Avalon, to which we have assigned proved undeveloped reserves. +We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. +Antelope Ridge Asset Area - Lea County, New Mexico +In the Antelope Ridge asset area, we turned to sales 20 gross (16.8 net) operated wells and 18 gross (0.9 net) non-operated wells during 2023. +The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to an approximately 75% NRI on most fee leases today. At the end of the first quarter of 2023, we achieved one of our five operational milestones we set for Matador in 2023 when we turned to sales eight gross (7.7 net) wells on the Rodney Robinson leasehold. These wells were the fourth group of wells drilled on the Rodney Robinson leasehold. The eight Rodney Robinson wells, which included four Second Bone Spring Carbonate, two Third Bone Spring Carbonate, and two Wolfcamp B completions, have produced in aggregate approximately 1.7 million BOE in approximately 10 months of production. +We turned to sales an additional 12 gross (9.1 net) operated wells in the Antelope Ridge asset area at various times during 2023. In total, these 12 Antelope Ridge wells, which included one First Bone Spring Sand, five Second Bone Spring Sand, two Third Bone Spring Sand, three Wolfcamp A and one Wolfcamp B completions, have produced in aggregate approximately 1.4 million BOE in an average of approximately six months of production. +Stateline Asset Area - Eddy County, New Mexico +During the second quarter of 2023, we achieved another of our five operational milestones when we turned to sales eight gross (8.0 net) wells in the Stateline asset area. These wells, which included four Wolfcamp B, two Upper Avalon and two Lower Avalon completions, have produced in aggregate approximately 1.8 million BOE in approximately six months of production. These eight wells had average completed lateral lengths of approximately 11,100 feet. +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales 40 gross (33.1 net) operated wells and 11 gross (0.7 net) non-operated wells during 2023. In the Twin Lakes asset area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2023. +In the third quarter of 2023, we achieved another of our five operational milestones when we turned to sales 21 gross (20.4 net) wells in the Ranger asset area that were acquired as part of the Advance Acquisition. Each of these wells had a lateral length of 2.25 miles, resulting in approximately 240,000 completed lateral feet, which was the largest single batch development project in Matador’s history. These wells included three Second Bone Spring Carbonate, six Second Bone Spring Sand, six Third Bone Spring Carbonate, three Third Bone Spring Sand and three Wolfcamp A completions, which averaged 24-hour initial production tests of 1,600 BOE per day with oil cuts averaging 84% and have in aggregate produced 2.4 million BOE in approximately four months of production. +We turned to sales an additional 19 gross (12.7 net) wells in the Ranger asset area at various times during 2023, which included three First Bone Spring Sand, seven Second Bone Spring Sand, one Third Bone Spring Carbonate, seven Third Bone Spring Sand and one Wolfcamp A completions. These wells have in aggregate produced 2.1 million BOE in an average of approximately six months of production. +Arrowhead Asset Area - Eddy County, New Mexico +During the fourth quarter of 2023, we achieved another of our five operational milestones when we turned to sales 17 gross (10.6 net) Stebbins wells in the Arrowhead asset area. These wells, which included eight Wolfcamp A, seven Second Bone Spring and two First Bone Spring completions, have produced in aggregate approximately 1.2 million BOE in approximately two months of production. These 17 wells had average completed lateral lengths of approximately 8,800 feet. +We also turned to sales 30 gross (1.8 net) non-operated wells in the Arrowhead asset area during 2023. +9 +Table of Contents +West Texas Asset Area - Loving and Ward Counties, Texas +During the fourth quarter of 2023, we achieved another of our five operational milestones when we turned to sales 13 gross (11.2 net) wells in the Wolf portion of the West Texas asset area. These wells, which included seven Wolfcamp B, five Wolfcamp A and one Third Bone Spring Carbonate completions, have produced in aggregate approximately 0.6 million BOE in approximately two months of production. These 13 wells had average completed lateral lengths of approximately 10,600 feet. +We also turned to sales 17 gross (0.2 net) non-operated wells in the West Texas asset area during 2023. +Rustler Breaks Asset Area - Eddy County, New Mexico +We turned to sales 21 gross (14.3 net) operated wells in the Rustler Breaks asset area at various times in the first, second and third quarters of 2023. In total, these 21 Rustler Breaks wells, which included two First Bone Spring Sand, eight Second Bone Spring Sand, six Wolfcamp A and five Wolfcamp B completions, have produced in aggregate approximately 3.9 million BOE in an average of approximately eight months of production. +We also turned to sales 23 gross (1.8 net) non-operated wells in the Rustler Breaks asset area during 2023. +South Texas — Eagle Ford Shale and Other Formations +At December 31, 2023, our properties included approximately 14,400 gross (12,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 76% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2023. +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2023, although we did participate in one gross (0.4 net) non-operated well that turned to sales in 2023. In fact, as of December 31, 2023, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 22% to 1,068 BOE per day, including 755 Bbl of oil per day and 1.9 MMcf of natural gas per day, during 2023, as compared to 1,373 BOE per day, including 971 Bbl of oil per day and 2.4 MMcf of natural gas per day, during 2022. For each of the years ended December 31, 2023 and 2022, 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2023, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.0 million BOE, was attributable to the Eagle Ford shale, including approximately 2.1 million Bbl of oil and 5.5 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and less than 1% of our proved natural gas reserves at December 31, 2023, essentially unchanged from December 31, 2022. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells that were turned to sales in 2023. +At December 31, 2023, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2023. +For the year ended December 31, 2023, approximately 3% of our average daily oil equivalent production, or 4,025 BOE per day, including five Bbl of oil per day and 24.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or 3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2023, approximately 7% of our daily natural gas production, or 24.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to these properties. At December 31, 2023, approximately 1% of our estimated total proved reserves, or 4.4 million BOE, was attributable to our properties in Northwest Louisiana. +10 +Table of Contents +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the West Texas asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks asset area and in Loving County, Texas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. Through January 31, 2023, we had earned all of the potential $73.5 million in performance incentives. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through mid-2024 , plus additional performance incentives for securing volumes from third-party customers. Through February 20, 2024, we had received $85.7 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and the other midstream facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2023, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +At December 31, 2023, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2023, San Mateo was gathering or transporting almost all our operated natural gas +11 +Table of Contents +production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area. +In addition, at December 31, 2023, San Mateo had an NGL pipeline connection at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners LP. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In the Wolf portion of the West Texas asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the West Texas asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2023, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2023, San Mateo gathered an average of approximately 358 MMcf of natural gas per day, an increase of 25% as compared to 287 MMcf of natural gas per day gathered during the year ended December 31, 2022. In addition, during the year ended December 31, 2023, San Mateo processed approximately 381 MMcf of natural gas per day at the Black River Processing Plant, an increase of 32%, as compared to 289 MMcf of natural gas per day processed during the year ended December 31, 2022. Natural gas gathering and processing volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. +At December 31, 2023, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and (iii) approximately 70 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. During the year ended December 31, 2023, Pronto processed an average of approximately 41 MMcf of natural gas per day. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +At December 31, 2023, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the West Texas asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2023, we estimated almost all of our oil production from the Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area was transported by pipeline. +At December 31, 2023, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2023, the San Mateo Oil Pipeline Systems had throughput of approximately 43,600 Bbl of oil per day, a decrease of 10%, as compared to throughput of approximately 48,300 Bbl of oil per day during the year ended December 31, 2022. +Produced Water Gathering and Disposal Assets +During 2023, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 20, 2024, San Mateo had nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area. At February 20, 2024, San Mateo had designed disposal capacity of approximately 475,000 Bbl of produced water per day. +During the year ended December 31, 2023, San Mateo handled approximately 376,000 Bbl of produced water per day, an increase of 4%, as compared to approximately 361,000 Bbl of produced water per day handled during the year ended December 31, 2022. +12 +Table of Contents +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo or Pronto. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2023, 2022 and 2021. +Year Ended December 31, +2023 2022 2021 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 27,542 21,943 17,840 +Natural gas (Bcf) 123.4 99.3 81.7 +Total oil equivalent (MBOE) (1) +48,112 38,495 31,454 +Average daily production (BOE/d) (1) +131,813 105,465 86,176 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 77.88 $ 96.32 $ 67.58 +Oil, with realized derivatives (per Bbl) $ 77.88 $ 92.87 $ 56.70 +Natural gas, without realized derivatives (per Mcf) $ 3.25 $ 7.98 $ 6.06 +Natural gas, with realized derivatives (per Mcf) $ 3.17 $ 7.15 $ 5.74 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 5.50 $ 7.33 $ 5.69 +Lease operating $ 5.06 $ 4.08 $ 3.46 +Plant and other midstream services operating $ 2.68 $ 2.48 $ 1.95 +Depletion, depreciation and amortization $ 14.90 $ 12.11 $ 10.97 +General and administrative $ 2.29 $ 3.02 $ 3.06 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 27,264 276 — 2 27,542 +Natural gas (Bcf) 113.9 0.7 8.2 0.6 123.4 +Total oil equivalent (MBOE) (3) +46,253 390 1,373 96 48,112 +Percentage of total annual net production 96.1 % 0.8 % 2.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 74,697 755 — 5 75,457 +Natural gas (MMcf/d) 312.1 1.9 22.6 1.5 338.1 +Total oil equivalent (BOE/d) 126,720 1,068 3,761 264 131,813 +Average Sales Prices (4) +Oil (per Bbl) $ 77.90 $ 76.10 $ — $ 74.53 $ 77.88 +Natural gas (per Mcf) $ 3.32 $ 3.54 $ 2.23 $ 2.09 $ 3.25 +Total oil equivalent (per BOE) $ 54.10 $ 60.01 $ 13.39 $ 13.61 $ 52.91 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.99 $ 32.78 $ 4.59 $ 17.79 $ 6.19 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +13 +Table of Contents +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 21,585 355 — 3 21,943 +Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3 +Total oil equivalent (MBOE) (3) +36,550 501 1,383 61 38,495 +Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 59,139 971 — 9 60,119 +Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1 +Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465 +Average Sales Prices (4) +Oil (per Bbl) $ 96.34 $ 95.23 $ — $ 91.53 $ 96.32 +Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98 +Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 17,279 558 — 3 17,840 +Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7 +Total oil equivalent (MBOE) (3) +29,395 776 1,217 66 31,454 +Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 47,339 1,528 — 9 48,876 +Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8 +Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176 +Average Sales Prices (4) +Oil (per Bbl) $ 67.65 $ 65.41 $ — $ 64.40 $ 67.58 +Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06 +Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023 increased 25% from our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022. This increased production was primarily attributable to the Advance Acquisition and to our delineation and development operations in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, as compared to 105,465 BOE per day for the year ended December 31, 2022. Our average daily oil production for the year ended December 31, 2023 was 75,457 Bbl of oil per day, an increase of 26% from 60,119 Bbl of oil per day for the year ended December 31, 2022. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf of natural gas per day, an increase of 24% from 272.1 MMcf of natural gas per day for the year ended December 31, 2022. +Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022 increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to 86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was 272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended December 31, 2021. +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2023. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 84% in all wells that we operated at December 31, 2023. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +1,300 666.8 175 89.4 1,475 756.2 +South Texas: +Eagle Ford (2) +89 72.1 — — 89 72.1 +Northwest Louisiana: +Haynesville — — 256 18.1 256 18.1 +Cotton Valley (3) +— — 66 39.0 66 39.0 +Area Total — — 322 57.1 322 57.1 +Total 1,389 738.9 497 146.5 1,886 885.4 +__________________ +(1) Includes 223 gross (89.9 net) vertical wells that were primarily acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(3) Includes the Cotton Valley formation and shallower zones. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2023, 2022 and 2021. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +16 +Table of Contents +At December 31, (1) +2023 2022 2021 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 272,277 196,289 181,306 +Natural Gas (Bcf) 1,126.8 962.6 852.5 +Total (MBOE) (3) +460,070 356,722 323,397 +Estimated proved developed reserves: +Oil (MBbl) 161,642 116,030 102,233 +Natural Gas (Bcf) 782.7 632.9 546.2 +Total (MBOE) (3) +292,097 221,507 193,262 +Percent developed 63.5 % 62.1 % 59.8 % +Estimated proved undeveloped reserves: +Oil (MBbl) 110,635 80,259 79,073 +Natural gas (Bcf) 344.0 329.7 306.4 +Total (MBOE) (3) +167,973 135,215 130,135 +Standardized Measure (4) (in millions) +$ 6,113.5 $ 6,983.2 $ 4,375.4 +PV-10 (5) (in millions) +$ 7,704.1 $ 9,132.2 $ 5,347.6 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2023 were $74.70 per Bbl for oil and $2.64 per MMBtu for natural gas, for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas and for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2023, 2022 and 2021 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2023, 2022 and 2021 were $1.59 billion, $2.15 billion and $972.2 million, respectively. +Our estimated total proved oil and natural gas reserves increased 29% from 356.7 million BOE at December 31, 2022 to 460.1 million BOE at December 31, 2023. This increase in proved oil and natural gas reserves was primarily attributable to the Advance Acquisition and our delineation and development operations in the Delaware Basin during 2023. We increased our total proved oil and natural gas reserves by 109.1 million BOE as a result of acquisitions and trades during 2023. We also added 88.3 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2023, of which 27.6 million BOE resulted from new well locations turned to sales during 2023 to establish proved developed reserves and 60.7 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2023. These increases were partially offset by the removal of 17.4 million BOE resulting from the 17% decrease in oil prices and the 58% decrease in natural gas prices used to estimate total proved reserves at December 31, 2023, as compared to December 31, 2022, and the removal of 31.5 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 31.5 million BOE to proved reserves at a future date. +Our proved oil reserves grew 39% from approximately 196.3 million Bbl at December 31, 2022 to approximately 272.3 million Bbl at December 31, 2023. Our proved natural gas reserves increased 17% from 962.6 Bcf at December 31, 2022 to 1.13 Tcf at December 31, 2023. Our proved reserves to production ratio at December 31, 2023 was 9.6, an increase of 3% from 9.3 at December 31, 2022. +17 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves decreased 12% from $6.98 billion at December 31, 2022 to $6.11 billion at December 31, 2023. The PV-10 of our total proved oil and natural gas reserves decreased 16% from $9.13 billion at December 31, 2022 to $7.70 billion at December 31, 2023. The decreases in our Standardized Measure and PV-10 are primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2023, as compared to December 31, 2022, partially offset by the 29% increase in our total proved oil and natural gas reserves at December 31, 2023, as compared to December 31, 2022. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2023 were $74.70 per Bbl and $2.64 per MMBtu, a decrease of 17% and 58%, respectively, as compared to average oil and natural gas prices of $90.15 per Bbl and $6.36 per MMBtu used to estimate proved reserves at December 31, 2022. Our total proved reserves were made up of 59% oil and 41% natural gas at December 31, 2023 and 55% oil and 45% natural gas at December 31, 2022. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2023. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2022 221,507 +Extensions and discoveries 27,615 +Net acquisitions of minerals-in-place 70,230 +Revisions of prior estimates (14,071) +Production (48,112) +Conversion of proved undeveloped to proved developed 34,928 +As of December 31, 2023 292,097 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 32% from 221.5 million BOE at December 31, 2022 to 292.1 million BOE at December 31, 2023. We added 27.6 million BOE in proved developed reserves through extensions and discoveries during 2023, which resulted from new well locations drilled during 2023 to establish proved reserves. In addition, during 2023, we converted 34.9 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. We also increased our proved developed reserves by 70.2 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. Additionally, we realized approximately 14.1 million BOE in net downward revisions of prior estimates, most of which were attributable to the lower commodity prices used to estimate proved reserves at December 31, 2023, which resulted in shorter estimated economic lives for certain of our producing properties. These cumulative net increases of 118.7 million BOE to our proved developed reserves exceeded by 2.5 times our total oil and natural gas production of 48.1 million BOE in 2023. +Our proved developed oil reserves increased 39% from 116.0 million Bbl at December 31, 2022 to 161.6 million Bbl at December 31, 2023. Our proved developed natural gas reserves increased 24% from 632.9 Bcf at December 31, 2022 to 782.7 Bcf at December 31, 2023. Proved developed reserves constituted 63% of our total proved oil and natural gas reserves at December 31, 2023, as compared to 62% at December 31, 2022. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2023. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2022 135,215 +Extensions and discoveries 60,724 +Net acquisitions of minerals-in-place 38,872 +Revisions of prior estimates (31,910) +Conversion of proved undeveloped to proved developed (34,928) +As of December 31, 2023 167,973 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +Our proved undeveloped oil and natural gas reserves increased 24% from 135.2 million BOE at December 31, 2022 to 168.0 million at December 31, 2023. We added 60.7 million BOE in proved undeveloped reserves through extensions and discoveries during 2023, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2023. In addition, we increased our proved undeveloped reserves by 38.9 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. These increases were partially offset by approximately 31.9 million BOE in net downward revisions of prior estimates of proved undeveloped reserves, most of which were attributable to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. During 2023, we also converted 34.9 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. +At December 31, 2023, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2023 within five years of booking these reserves. The following table sets forth, since 2020, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2020 16,256 76.1 28,944 $ 257,590 +2021 23,965 96.6 40,071 240,664 +2022 22,515 95.3 38,403 434,336 +2023 18,492 98.6 34,928 441,671 +Total 81,228 366.6 142,346 $ 1,374,261 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +19 +Table of Contents +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2023. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 270,136 1,094.9 452,616 $ 6,070.5 $ 7,649.9 +South Texas: +Eagle Ford (5) +2,135 5.5 3,048 35.9 45.3 +Northwest Louisiana +Haynesville — 23.1 3,847 10.5 13.2 +Cotton Valley (6) +6 3.3 559 (3.4) (4.3) +Area Total 6 26.4 4,406 7.1 8.9 +Total 272,277 1,126.8 460,070 $ 6,113.5 $ 7,704.1 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2023 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2023 were approximately $1.59 billion. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2023. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from +20 +Table of Contents +Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2023. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 218,900 118,900 46,700 33,300 265,600 152,200 +South Texas: +Eagle Ford 14,400 12,100 — — 14,400 12,100 +Northwest Louisiana: +Haynesville 16,200 8,900 — — 16,200 8,900 +Cotton Valley 15,700 14,800 — — 15,700 14,800 +Area Total (1) +18,500 17,300 — — 18,500 17,300 +Total 251,800 148,300 46,700 33,300 298,500 181,600 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2023 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2029 and beyond totals 2,600 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2023. +Acres Acres Acres Acres Acres +Expiring 2024 Expiring 2025 Expiring 2026 Expiring 2027 Expiring 2028 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +5,100 2,800 10,100 5,200 10,200 4,500 11,700 11,400 6,700 6,700 +Total 5,100 2,800 10,100 5,200 10,200 4,500 11,700 11,400 6,700 6,700 +__________________ +(1) Approximately 66% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2023, +21 +Table of Contents +our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2023, approximately 3% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2023, 2022 and 2021 . +Year Ended December 31, +2023 2022 2021 +Gross Net Gross Net Gross Net +Development Wells +Productive 222 84.1 138 61.4 96 40.2 +Dry — — — — — — +Exploration Wells +Productive (1) +24 16.9 20 11.0 8 8.0 +Dry — — — — — — +Total Wells +Productive (2) +246 101.0 158 72.4 104 48.2 +Dry — — — — — — +(1) All of these wells are extension wells. +(2) Includes one gross (0.5 net) vertical well in 2023 and three gross (1.6 net) vertical wells in 2022. +At December 31, 2023, we had a total of 46 gross (37.8 net) development wells and six gross (4.9 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also generally deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted NGLs based on either a negotiated percentage of the proceeds that are generated from the sale of NGLs or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include, but are not limited to: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions or conflicts in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases such as COVID-19 and its variants; the continued threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and +22 +Table of Contents +production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled or unscheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2023, 2022 and 2021, we had three significant purchasers that accounted for approximately 76%, 70% and 72%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +23 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo and Pronto compete with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, acquire properties and provide competitive midstream services will depend upon our ability to conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Environmental +Emissions Mitigation +We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines with expected sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities. +Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control and Data Acquisition (“SCADA”) equipment at a number of our larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require. +Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions. +Water Management +Using improving technologies, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations. +Land Stewardship +24 +Table of Contents +We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S. Department of Interior Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations. +During 2023, 94% of our gross operated oil production and 98% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil, natural gas and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water. This is significant because it both (i) reduces truck traffic and increases road safety and (ii) reduces emissions. +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. +Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions +25 +Table of Contents +having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states, including Texas, in August 2022. The Department of the Interior has recently resumed lease sales in several states. +In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under NEPA in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. BLM later announced that drilling permit approvals could be considered for the subject leases, provided that the process included additional time for public comments and objections. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits, is uncertain. +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the Environmental Protection Agency (the “EPA”) suggested increasing the value of the social cost of greenhouse gases from $51 per metric ton to $190 per metric ton, and in December 2023, the EPA used $190 per metric ton as the social cost of greenhouse gases in its final rule revising New Source Performance Standards (“NSPS”) and Emission Guidelines for greenhouse gas and volatile organic compound emissions in the oil and gas sector. As part of this final rulemaking, the EPA published a peer-reviewed report on the updated social cost of greenhouse gases estimates. Future EPA rulemakings may also incorporate the methodology and social cost of greenhouse gases estimate developed in this report and result in more stringent rules and regulations affecting the oil and gas sector. +In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In November 2023, the federal district court for the District of Columbia dismissed the case, holding that the environmental groups lacked standing. The environmental groups have appealed the district court’s ruling, and their appeal remains pending. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits. +In November 2022, the BLM proposed a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. The proposed rule has not yet been adopted. +26 +Table of Contents +Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Pipeline Regulation +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum +27 +Table of Contents +distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The final 2019 gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In September 2023, PHMSA issued a proposed rule applicable to gas transmission and distribution and gathering pipelines, which would require updates to emergency response plans and other safety practices. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +Underground Injection and Hydraulic Fracturing +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure +28 +Table of Contents +the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to +29 +Table of Contents +administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the EPA and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On January 18, 2023, the EPA and the Corps jointly issued a final rule revising the definition of WOTUS that largely returned to the pre-2015 regulatory regime. On September 8, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands only to those that have a continuous surface connection to water bodies. On August 29, 2023, the EPA and the Corps jointly issued a final rule, which took effect immediately, aligning the regulatory definition of WOTUS with the Supreme Court’s ruling. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration +30 +Table of Contents +and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. +In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort is designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. On December 2, 2023, the EPA issued a prepublication version of a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources. Additionally, on November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. As another example, in January 2023, the EPA announced a proposed consent decree that, if finalized as proposed, would establish a December 10, 2024 deadline for the EPA to review and propose revisions to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. +31 +Table of Contents +Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. On July 3, 2023, the USFWS issued a proposed rule to list the dunes sagebrush lizard as endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate and our ability to maximize production from our leases may be adversely impacted by these restrictions. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated +32 +Table of Contents +properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2023, we had 395 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2023, for example, our employees completed approximately 22,000 hours of continuing education and study, equating to approximately 59 hours per employee. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +33 +Table of Contents +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +34 +Table of Contents +Item 1A. Risk Factors. +Summary of Risk Factors +The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition, results of operations and cash flows. You should read this summary together with the more detailed risk factors contained below. +Risks Related to our Financial Condition +• Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. +• Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. +• We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and Israel and Hamas. +• Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. +• Our oil and natural gas reserves are estimated, and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +• The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +• Approximately 39% of our total proved reserves at December 31, 2023 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +• Unless we replace our oil and natural gas reserves, our reserves and production will decline. +• We may be required to write down the carrying value of our proved properties under accounting rules. +• Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +• Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. +• Our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. +• We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. +• We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +• Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +Risks Related to our Liquidity +• We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. +• The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +• The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations. +• Our credit rating may be downgraded, which could reduce our financial flexibility. +• Dividend payments are at the discretion of our Board of Directors and subject to numerous factors. +Risks Related to our Operations +• Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk. +• Our operations are subject to operational hazards and risks, and insurance against all such risks is not available to us. +• Our reserves and production are concentrated in a few core areas. +• There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. +• Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. +• Multi-well pad drilling may result in volatility in our operating results. +• The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. +• We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. +• Regulatory changes could prevent our ability to continue to pool wells in accordance with our past practices. +• Midstream projects are subject to risks of construction delays and cost over-runs. +35 +Table of Contents +• Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. +• The seismic data and other technologies we use cannot eliminate exploration risk. +Risks Related to Third Parties +• Financial difficulties encountered by purchasers, operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +• The marketability of our production is dependent upon gathering, processing and transportation facilities. +• We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. +• San Mateo’s and Pronto’s long-term success depends on their ability to obtain new sources of products, which depends on certain factors beyond their control. +• Certain of our long-term contracts require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and may limit our ability to use other service providers. +• We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +• Competition in our industry is intense, and our competitors may use superior technology and data resources. +• Strategic relationships upon which we may rely are subject to change. +• We have limited control over activities on properties we do not operate. +Risks Related to Laws and Regulations +• Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations. +• We are subject to government regulation, including complex environmental laws, which could require significant expenditures. +• We are subject to tax laws and may become subject to new taxes, or tax deductions currently available to us may be eliminated or reduced. +• Legislation and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs and additional operating restrictions or delays, and the physical effects of climate change could disrupt our production and cause us to incur significant costs. +• New climate disclosure rules proposed by the SEC or states in which we have operations or do business could increase our costs of compliance. +• We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +• A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets. +• The rates of our regulated assets are subject to review and reporting by federal regulators. +• Should we fail to comply with FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +• Derivatives legislation adopted by Congress could limit our ability to hedge risks associated with our business. +Risks Relating to Our Common Stock +• The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +• Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect us. +• Future sales and offerings of our common stock could depress the price of our common stock. +• Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. +• The issuance of preferred stock could diminish the rights of holders of our common stock. +General Risk Factors +• We may have difficulty managing growth in our business. +• The loss of any key personnel or Board member could disrupt our business operations. +• A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +• Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. +• We operate in a litigious environment and may be involved in legal proceedings. +Risks Related to our Financial Condition +Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations. +The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGLs are commodities and, +36 +Table of Contents +therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2023, oil prices averaged $77.60 per Bbl, as compared to $94.33 per Bbl in 2022, ranging from a high of $93.68 per Bbl in late September to a low of $66.74 per Bbl in mid-March, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2023, natural gas prices averaged $2.66 per MMBtu, as compared to $6.54 per MMbtu in 2022, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2023, natural gas prices ranged from a low of $1.99 per MMBtu in late March to a high of $4.17 per MMBtu in early January before finishing the year at $2.51 per MMBtu. +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following: +• the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; +• the actions of OPEC+ and state-controlled oil companies; +• the prices and availability of competitors’ supplies of oil, natural gas and NGLs; +• the price and quantity of foreign imports; +• the impact of U.S. dollar exchange rates; +• domestic and foreign governmental regulations and taxes; +• speculative trading of oil and natural gas futures contracts; +• the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; +• the availability of refining capacity; +• the prices and availability of alternative fuel sources; +• weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; +• political conditions or conflicts in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; +• the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; +• domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, such as COVID-19 and its variants; +• the continued threat of terrorism and the impact of military action and civil unrest; +• public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing activities; +• the level of global oil, natural gas and NGL inventories and exploration and production activity; +• the impact of energy conservation efforts; +• technological advances affecting energy consumption; and +• overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relation to each other. +Declines in oil, natural gas or NGL prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. Should oil, natural gas or NGL prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial +37 +Table of Contents +condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. +Inflation in the U.S. has become much more significant in recent years. Throughout 2022 and 2023, we experienced significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others, as a result of the recent increases in oil and natural gas prices, as well as availability constraints, supply chain disruptions, increased demand, labor shortages and wage increases associated with a low U.S unemployment rate, inflation and other factors. Supply and demand fundamentals have been aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as related actions of the U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps. Should oil and natural gas prices remain at their current levels or increase, we expect to be subject to additional supply chain constraints and service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughout the U.S. and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flows. +We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and Israel and Hamas and the related humanitarian crises on the global economy, energy markets, geopolitical stability and our business. +Although our leasehold acreage is located primarily in the Delaware Basin, the broader consequences of the conflicts between Russia and Ukraine and Israel and Hamas, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of either conflict’s effect on our business and results of operations as well as on the global economy and energy markets. +Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement, the San Mateo Credit Facility or otherwise may not be sufficient to fund all of our future capital expenditures or future acquisitions. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• our estimated proved oil and natural gas reserves; +• the amount of oil and natural gas we produce; +• the prices at which we sell our production; +• the costs of developing and producing our oil and natural gas reserves; +• the costs of constructing, operating and maintaining our midstream facilities; +• our ability to attract third-party customers for our midstream services; +• our ability to acquire, locate and produce new reserves; +• the ability and willingness of banks or other financial institutions to lend to us; and +• our ability to access the equity and debt capital markets. +38 +Table of Contents +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak or resurgence of contagious or pandemic diseases, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to develop our properties, pay for higher service costs, fund acquisitions, increase our rate of growth, or expand our midstream operations, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. +Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• the quality and quantity of available data; +• the interpretation of that data; +• the judgment of the persons preparing the estimate; and +• the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of certain of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• actual prices we receive for oil and natural gas; +39 +Table of Contents +• actual costs and timing of development and production expenditures; +• the amount and timing of actual production; and +• changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 39% of our total proved reserves at December 31, 2023 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +At December 31, 2023, approximately 37% of our total proved reserves were undeveloped and approximately 2% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have: +• downward adjustments to our estimated proved reserves; +• increases in our estimates of development costs; or +• deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +To manage our exposure to price risk, including price differential risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” +40 +Table of Contents +to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap, as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. +A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows. +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. +Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in 2020 and 2021, these price differentials for natural gas widened in 2022 and 2023 and could widen further in future periods. Should we experience future periods of negative pricing for natural gas as we have experienced historically, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. +A component of our growth may come through acquisitions, and our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +In addition, the success of our acquisitions will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the acquired assets and operations into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of our acquisitions. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our management team may be required to devote +41 +Table of Contents +considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. Difficulties in integrating our acquisitions into our company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others: +• the inability to successfully integrate our acquisitions operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from such acquisitions; +• not realizing anticipated operating synergies; and +• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with such acquisitions. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the borrowing of funds, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations. +Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We may not perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. Even when problems with a property or asset are identified, the seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other risks and liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost. +It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. A failure to cure any title defects may delay or prevent us from utilizing the associated leasehold right or mineral interest, which may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has +42 +Table of Contents +greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +Risks Related to our Liquidity +We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs. +As of February 20, 2024, the maximum facility amount under the Credit Agreement was $2.00 billion, the borrowing base was $2.50 billion and our elected borrowing commitment was $1.325 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). At February 20, 2024, we had available borrowing capacity of approximately $772.6 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such +43 +Table of Contents +repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of unrestricted cash and cash equivalents), divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less and a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of equal to or greater than 1.0 to 1.0 at the end of each fiscal quarter. +As of February 20, 2024, the facility amount under the San Mateo Credit Facility was $535.0 million, and San Mateo had available borrowing capacity of approximately $36.0 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $735.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. In addition to these restrictions, the San Mateo Credit Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. +In the future, subject to the restrictions in the indentures governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including the following: +• requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• increasing our vulnerability to general adverse economic and industry conditions; +• placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• increasing the risk that we may default on our debt obligations. +The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 20, 2024, our borrowing base was $2.50 billion, our elected borrowing commitment was $1.325 billion, the maximum facility amount under the Credit Agreement was $2.00 billion and we had $500.0 million in outstanding borrowings under, and approximately $52.4 million in outstanding letters of credit issued pursuant to, the Credit Agreement. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenants noted above). We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a loan based on the secured overnight financing rate administered by the Federal Reserve Bank of New York (“SOFR”). If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds +44 +Table of Contents +Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for a one month tenor, plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% depending on the level of borrowings under the Credit Agreement. If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.25% to 2.25% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.25% to 3.25% depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +Interest rates rose significantly during 2022 and remained elevated throughout 2023 as the Federal Reserve sought to control inflation. Interest rates may remain high or increase during 2024. Our Credit Agreement and the San Mateo Credit Facility have floating rates tied to SOFR or other interest rate benchmarks that generally rise alongside the increase in the federal funds rates. As a result, interest expense on our existing floating rate debt rose during 2022 and 2023 and may remain high or increase during 2024. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. +The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions. +Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to: +• incur or guarantee additional debt or issue certain types of preferred stock; +• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• transfer or sell assets; +• make certain investments; +• create certain liens; +• enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indentures governing our outstanding senior notes) to us; +• consolidate, merge or transfer all or substantially all of our assets; +• engage in transactions with affiliates; and +• create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less and a current ratio, which is defined as current assets plus the unused availability under the Credit Agreement, divided by current liabilities, of equal to or greater than 1.0 to 1.0. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant. +Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or +45 +Table of Contents +otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indentures governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations. +In March 2020, our corporate credit rating from S&P Global Ratings was downgraded from “B+” to “B-” and our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades resulted in significant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services subsequently upgraded our corporate credit rating to “B2” in July 2020, to “B1” in September 2021 and to “Ba3” in September 2022. S&P Global Ratings upgraded our corporate credit rating to “B” in June 2021, “B+” in January 2022 and “BB-” in September 2022. In September 2021, Fitch Ratings assigned us a corporate credit rating of “B+” and subsequently upgraded our corporate credit rating to “BB-” in September 2022. As of February 20, 2024, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “BB-,” “Ba3” and “BB-,” respectively. We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. We intend to continue to pay a quarterly dividend in the future pursuant to the dividend policy adopted by our Board. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available. +We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indentures governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price. +Risks Related to our Operations +Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during +46 +Table of Contents +drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: +• general economic and industry conditions, including the prices received for oil and natural gas; +• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• potential drainage of oil and natural gas from our properties by operations on adjacent properties; +• the existence or magnitude of faults or unanticipated geological features; +• loss of or damage to oilfield development and service tools; +• accidents, equipment failures or mechanical problems; +• title defects of the underlying properties; +• increases in severance taxes; +• adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• inflation in exploration, drilling, completion and production costs; +• domestic and foreign governmental regulations; and +• proximity to and capacity of gathering, processing, transportation and disposal facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: +• landing our wellbore in the desired drilling zone; +• staying in the desired drilling zone while drilling horizontally through the formation; +• running our casing the entire length of the wellbore; +• fracture stimulating the planned number of stages; +• drilling out the plugs between stages following hydraulic fracturing operations; and +• being able to run tools and other equipment consistently through the horizontal wellbore. +Each of these risks is magnified in wells with longer laterals. In 2023, the average completed lateral length for operated wells turned to sales was approximately 9,800 feet. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• natural disasters; +• adverse weather conditions, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; +47 +Table of Contents +• domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, such as COVID-19 and its variants; +• loss of drilling fluid circulation; +• blowouts where oil or natural gas flows uncontrolled at a wellhead; +• cratering or collapse of the formation; +• pipe or cement leaks, failures or casing collapses; +• damage to pipelines, processing plants and disposal wells and associated facilities; +• fires or explosions; +• releases of hazardous substances or other waste materials that cause environmental damage; +• pressures or irregularities in formations; and +• equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. The protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production. In addition, if such a seismic event occurred in the area of the Company’s or San Mateo’s operations, the Company or San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. Any such further events could adversely impact our and San Mateo’s revenues and cash flows. +There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Marlan Processing Plant and the Black River Processing Plant. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant or the Marlan Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s and Pronto’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s or Pronto’s costs to access and transport on these third-party pipelines significantly increase, their profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo or Pronto gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected. +Insurance against all operational risks is not available to us. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable +48 +Table of Contents +or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 96% of our total oil and natural gas production for 2023 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2024 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well opportunities in our South Texas and Haynesville shale positions. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled or unscheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut-ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows. +There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value. +As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows. +Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. +49 +Table of Contents +Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. +Multi-well pad drilling may result in volatility in our operating results. +We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. +The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. Further, supply chain disruptions and other inflationary pressures being experienced throughout the United States and global economy may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could +50 +Table of Contents +increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could have a material adverse impact on our future production results. +In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production. +Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity. +From time-to-time, we, through San Mateo, Pronto or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity, financial condition and the ability of San Mateo or Pronto to attract third-party customers. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our drilling locations on federal lands may not be drilled as scheduled. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. +At December 31, 2023, we had leasehold interests in approximately 30,600 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2029. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be +51 +Table of Contents +able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Risks Related to Third Parties +Financial difficulties encountered by our oil, natural gas and NGL purchasers, third-party operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For each of the years ended December 31, 2023, 2022 and 2021, we had three significant purchasers that collectively accounted for approximately 76%, 70% and 72%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows. +In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate and from San Mateo’s and Pronto’s customers. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be adversely affected. +The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line +52 +Table of Contents +repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. +The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. For example, in January 2024, we experienced temporary natural gas pipeline and processing interruptions due to maintenance and constraints that are estimated to have resulted in approximately 5,500 BOE per day of less production. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2024. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows. +We own and operate substantially all of our midstream assets in Eddy County, New Mexico and Loving County, Texas through San Mateo, and we have and may continue to enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control. In addition, if our joint venture partners do not fulfill their contractual, financial and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for certain joint ventures and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because of the natural decline in production in the regions of San Mateo’s and Pronto’s midstream operations, San Mateo’s and Pronto’s long-term success depend on their ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s and Pronto’s control. Any decrease in supplies to their midstream facilities could adversely affect San Mateo’s and Pronto’s business and operating results. +San Mateo’s and Pronto’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s and Pronto’s gathering systems and the utilization rate at its other midstream facilities, San Mateo and Pronto must continually obtain new sources of products. San Mateo’s and Pronto’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo and Pronto have no control over the level of activity in the areas of their operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo and Pronto have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +53 +Table of Contents +We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2023, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $764.2 million over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service. +We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural gas and to secure trained personnel. Similarly, our midstream business, and particularly the success of San Mateo and Pronto, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo and Pronto compete with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to a competitive labor market, inflation and other factors, and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working +54 +Table of Contents +relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management and Board to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +We have limited control over activities on properties we do not operate. +We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• the timing and amount of capital expenditures; +• the operator’s expertise and financial resources; +• the rate of production of reserves, if any; +• approval of other participants in drilling wells; and +• selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +Risks Related to Laws and Regulations +Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands. +At December 31, 2023, Matador held approximately 152,200 net leasehold and mineral acres in the Delaware Basin, primarily in Eddy and Lea Counties, New Mexico and in Loving and Ward Counties, Texas, of which approximately 48,100 net acres, or about 32%, was on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. For example, on August 16, 2022, H.R. 5376, commonly known as the Inflation Reduction Act of 2022 (the “IRA”), was enacted. Pursuant to the IRA, the royalty rate for federal leases issued on or after August 16, 2022 was increased to 16.67 percent. On July 24, 2023, the BLM issued a proposed rule that would revise the BLM’s oil and gas leasing regulations, including aligning royalty rates, rentals, and minimum bids with the IRA, and would update the bonding requirements for leasing, development and production. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn +55 +Table of Contents +could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements that may be implemented or litigation regarding the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. A change in the presidential administration, as well as a closely divided Congress, may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for: +• personal injuries; +• property damage; +• containment and clean-up of oil, produced water and other spills; +• venting, flaring or other emissions; +• management and disposal of hazardous materials; +• remediation, clean-up costs and natural resource damages; and +• other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non- +56 +Table of Contents +governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA). +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. For example, on March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of southeastern New Mexico where we operate. On July 3, 2023, the USFWS issued a proposed rule to list the dunes sagebrush lizard as endangered. We participate in candidate conservation agreements for the lesser prairie-chicken, as well as the dunes sagebrush lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. The listing of the dunes sagebrush lizard as endangered, participation in such candidate conservation agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +Historically, we have generated and carried forward net operating losses (“NOL”) in amounts sufficient to offset substantially all of our taxable income and, thus, have not incurred material federal or state income tax liabilities. As of December 31, 2022, we had utilized all of our federal NOL carryovers. During 2023, we recognized research and experimental expenditure tax credits of $74.0 million, which had the effect of reducing our federal income tax liability for 2023. Our federal and state income tax liabilities in 2024 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods. +Additionally, the IRA contains a number of revisions to the Internal Revenue Code, including (i) a 15% corporate minimum income tax for certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending before the corporation’s current tax year, (ii) a 1% excise tax on corporate stock repurchases in tax years beginning after December 31, 2022 and (iii) expanded business tax credits and incentives for the development of clean energy projects and the production of clean energy. The impact of the 15% corporate minimum tax will depend on our results of operations each year. While we do not expect such minimum tax (or any other tax provision contained in the IRA) to have any immediate material impact, we will continue to evaluate its future impact as further information becomes available. +In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The passage of any such legislation or any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +57 +Table of Contents +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands, but these rules never became effective. These rules were rescinded by rule in December 2017. The rescission was challenged, and the challenge remains pending before the Ninth Circuit Court of Appeals. Separately, in 2016, BLM issued the 2016 Waste Prevention Rule to address flaring, venting and leaks from oil and natural gas operations on federal lands. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under federal leases. Under the authority of the IRA, on November 30, 2022, BLM proposed new regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on federal and Indian leases. In addition, in July 2023, the Louisiana Department of Natural Resources issued a proposed rule that would restrict routine venting and flaring of methane from oil and natural gas production facilities in the state. +Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders, if passed at the local, state or federal level could limit our operations. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. +While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt +58 +Table of Contents +water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. See “Business—Regulation—Environmental, Health and Safety Regulation.” +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on the use of injection wells by us or by third parties whom we may contract with to dispose of produced water. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. Any one or more of these developments may result in operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could adversely impact our business, cash flows and results of operations and could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended NDCs, which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020 but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting a goal to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of alternative sources of energy. On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and, for the first time ever, impose a fee on GHG emissions from certain facilities that exceed specified emissions levels. Further, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on methane and greenhouse gas emissions from new and existing sources in the oil and natural gas industry. On December 2, 2023, the EPA issued a prepublication version of a final rule to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA and creates new emissions restrictions for existing sources as well. On November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibits flaring in certain circumstances and requires upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. The EPA has begun adopting and implementing a comprehensive suite of regulations to restrict greenhouse gas emissions under existing provisions of the CAA and the recent authority of the IRA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting +59 +Table of Contents +our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes, droughts and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Any future exploration and development activities and equipment could also be adversely affected by severe weather conditions such as hurricanes or freezing temperatures, which may cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. Such severe weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our Operations—If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have a material adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors, investment fund managers and certain family foundations, universities, individual investors and sovereign wealth, pension and endowment funds, promoting divestment of, or limit investment in, fossil fuel equities and pressuring lenders to limit or stop funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders, limiting the issuance of federal drilling permits and other federal approvals. Also in 2021, President Biden issued an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +President Biden and the Democratic Party, which now controls the U.S. Senate, have identified climate change as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, promoting energy efficiency or the development and consumption of alternative forms of energy, or prohibiting or restricting oil and natural gas development activities in certain areas, have been proposed and/or promulgated during the Biden administration and additional such measures are likely. The Biden administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before 2050 is a critical priority, affirmed his administration’s desire to establish the United States as a leader in addressing climate change and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public +60 +Table of Contents +and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes. +New climate disclosure rules proposed by the SEC or states in which we have operations or do business could increase our costs of compliance and adversely impact our business. +On March 21, 2022, the SEC released proposed new rules that would require significantly expanded climate-related disclosures in SEC filings, including certain climate-related risks, climate-related metrics and greenhouse gas emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements. The proposed rules include certain phase-in compliance dates for disclosure of Scope 1, 2 and 3 greenhouse gas emissions. As initially proposed, large accelerated filers such as us would be obligated to disclose Scope 1 and 2 greenhouse gas emissions beginning in the first filing year in which the rules apply and disclose Scope 3 greenhouse gas emissions beginning in the following filing year. While we are currently assessing the proposed rule, the final form and substance of the rule is not yet known, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. In addition, in the absence of federal action, states may propose and adopt climate disclosure requirements. +In the event the SEC finalizes its proposed climate disclosure rule or states in which we operate or do business adopt climate disclosure requirements, we could incur significant additional costs relating to the assessment and disclosure of climate-related risks, including costs relating to monitoring, collecting, analyzing and reporting the new metrics and implementing systems and procuring additional internal and external personnel with the requisite skills and expertise to serve those functions. These additional costs or changes in operations could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain investors and lenders restricting or seeking more stringent conditions with respect to their investments in carbon-intensive sectors. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient. +New regulations on all emissions from our operations could cause us to incur significant costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the NSPS and NESHAP programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. In January 2023, the EPA announced a proposed consent decree that, if finalized as proposed, would establish a December 10, 2024 deadline for the EPA to review and propose revisions to the NESHAP for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. The EPA finalized a more stringent National Ambient Air Quality Standard for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, BLM issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules were designed to limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under Federal leases. Under the authority of the IRA, on November 30, 2022, BLM proposed new regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on Federal and Indian leases. If not withdrawn or significantly revised, these proposed rules are expected to result in an increase to our operating costs and changes in our operations. In December 2023, the EPA issued final NSPS updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations. +61 +Table of Contents +We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently finalized rulemaking to expand existing integrity management, reporting and records retention, and safety requirements to certain natural gas transmission lines. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. +The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +62 +Table of Contents +Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. +In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +Risks Relating to Our Common Stock +The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2023, our stock price fluctuated between a high of $69.41 and a low of $42.04. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• declaration of dividends or adjustments to our dividend policy; +• speculation in the press or investment community; +• announcement or consummation of acquisitions, dispositions or joint ventures by us; +• public reaction to our operations or plans, press releases, announcements and filings with the SEC; +• the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; +• the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations, such as the Biden Administration Federal Lease Orders; +63 +Table of Contents +• sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, such as COVID-19 and its variants; +• the realization of any of the risk factors presented in this Annual Report; +• the recruitment or departure of key personnel; +• commencement of, involvement in or unfavorable resolution of litigation; +• the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• changes in market valuations of companies similar to ours; and +• domestic and international economic, legal and regulatory factors unrelated to our performance. +Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price. +Attention from governmental and regulatory bodies, investors, consumers and other stakeholders on ESG practices, together with changes in consumer, industrial and commercial behavior, investor and societal expectations on companies to address climate change and to make voluntary disclosures related to climate change and sustainability, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons and the use of products manufactured with, or powered, by hydrocarbons, may result in the enactment of climate and ESG-related regulations, policies and initiatives at the government, regulator, corporate and/or investor community levels; technological advances with respect to the generation, transmission, storage and consumption of energy; and the development of, and increased demand from consumers for, lower-emission products and services. These developments may in the future result in increased costs (including increased costs associated with compliance, shareholder engagement, contracting and insurance) and reduced demand for products manufactured with, or powered by, petroleum products, as well as the demand for our products and services. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. +In addition, negative perceptions regarding our industry and reputational risks, including perceptions related to the sufficiency of our ESG program (which may include policies, practices and extralegal objectives related to climate change, environmental stewardship, social responsibility and corporate governance), may in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. In particular, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, sovereign wealth funds, university endowments, individual investors and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors and asset managers, both domestically and internationally, have published ESG guidelines and disclosure standards that companies in which they invest are expected to adopt or follow. +Certain other stakeholders have pressured commercial and investment banks and other capital providers to stop or limit funding of oil and natural gas projects and have pressured insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Institutional lenders that provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale plays. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected. +In addition, shareholder activism has been recently increasing in the oil and gas industry, and shareholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away +64 +Table of Contents +from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have an adverse effect on our stock price and our access to and costs of capital. +Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. +As of February 20, 2024, our directors and executive officers beneficially owned approximately 6.3% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +Our Board is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +General Risk Factors +We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo, Pronto or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team and the members of our Board, and the loss of any key personnel or Board member could disrupt our business operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment +65 +Table of Contents +agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +It has also been widely reported in the press and elsewhere that businesses have faced a more challenging hiring environment since the onset of the COVID-19 pandemic and the subsequent recovery, which has resulted in increased costs to attract skilled labor, such as higher wages or costs for contractors. We may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected. +A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities, including technologies that are managed by third-party service providers or other providers to our industry on whom we directly or indirectly rely to help us collect, host or process information. We depend on such digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our SCADA systems, control important processes and facilities that are critical to our operations. +While we and our third-party service providers commit resources to the design, implementation and monitoring of our information systems, there is no guarantee that these security measures will provide absolute security. Despite these security measures, we may not be able to anticipate, detect or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launch, and because attackers are increasingly using technologies designed to circumvent controls and avoid detection. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses, damage to our reputation and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. In addition, any failure of our third-party providers’ computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business. +While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our or our third-party providers’ systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, disruptions of our current or planned business operations or transactions, damage to our reputation or financial loss. Additionally, costs for insurance may also increase as a result of cybersecurity threats, and insurance against losses relating to cyber incidents may become more difficult to obtain. +As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and further enhance our protective systems or to investigate and remediate any vulnerabilities. In addition, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. Any failure by us to comply with any additional regulations could result in significant penalties and liability to us, and we cannot predict the potential impact to our business or the energy industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating to cybersecurity issues. +Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition of the Company or other change in control transaction that our shareholders may consider favorable. These provisions include: +66 +Table of Contents +• authorization for our Board to issue preferred stock without shareholder approval; +• a classified Board so that not all members of our Board are elected at one time; +• the prohibition of cumulative voting in the election of directors; and +• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +We operate in a litigious environment and may be involved in legal proceedings that could have a material adverse effect on our results of operations and financial condition. +Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 1C. Cybersecurity. +Risk Management and Strategy +The Company recognizes the importance of developing, implementing and maintaining cybersecurity measures to better safeguard our information systems and protect the confidentiality, integrity and availability of our data. +Managing Material Risks and Integrated Overall Risk Management +The Company has integrated cybersecurity into our broader risk management framework. Our risk management team works closely with our IT department to evaluate and address cybersecurity risks in alignment with our business objectives and operational needs. The Company requires the Board and employees to complete cybersecurity training related to the physical security of assets, data privacy and other information security policies and procedures. +Engage Third Parties on Risk Management +Recognizing the complexity and evolving nature of cybersecurity threats, the Company engages with a range of external experts, including cybersecurity consultants in evaluating and testing our risk management systems. Our collaboration with these third parties includes regular audits, threat assessments, penetration tests and consultation on security enhancements. +Oversee Third-Party Risk +Because we are aware of the risks associated with third-party vendors, service providers and business partners, we have implemented processes to oversee and manage these risks. We conduct initial risk assessments of third-party providers before engagement. These assessments include due diligence reviews of third parties that have access to our networks, confidential information and information systems in order to assess the risks from cybersecurity threats. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third parties. +Risks from Cybersecurity Threats +We have not been subject to cybersecurity challenges that have materially impaired our operations or financial standing. +67 +Table of Contents +Governance +The Company is aware of the critical nature of managing risks associated with cybersecurity threats and has established oversight mechanisms at the Board and management levels to ensure effective governance in managing risks associated with cybersecurity threats. +Board Oversight +The Board has oversight of cybersecurity risks and, specifically, the Audit Committee of the Board is charged with the oversight of the Company’s guidelines and policies to govern the process by which risk assessment and risk management are undertaken by management, including with respect to cybersecurity risks. Our Board is composed of members with diverse expertise, including risk management, technology and finance, which experience provides them with the skills needed to oversee cybersecurity risks effectively. +Management’s Role Managing Risk +The Company’s IT Committee, which includes senior executives and other members of management, meets regularly to monitor and discuss cybersecurity issues. The Senior Vice President of Information Technology, the Executive Vice President and Chief Accounting Officer (“CAO”) and the Co-Chief Operating Officer (“COO”) play a pivotal role in informing the Board on cybersecurity risks. They provide comprehensive briefings to the Board on a regular basis, with a minimum frequency of once per year. These briefings encompass a broad range of topics, including: +• current cybersecurity landscape and emerging threats; +• status of ongoing cybersecurity initiatives and strategies; +• incident reports and learnings from any cybersecurity events; and +• compliance with regulatory requirements and industry standards. +In addition to our scheduled meetings, the Board, Senior Vice President of Information Technology, CAO and COO maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive. The Board actively participates in strategic decisions related to cybersecurity, offering guidance and approval for major initiatives. This involvement ensures that cybersecurity considerations are integrated into the broader strategic objectives of the Company. +Risk Management Personnel +Primary responsibility for assessing, monitoring and managing our cybersecurity risks rests with the Senior Vice President of Information Technology. With over 35 years of experience in the information technology field, he brings a wealth of expertise to his role. His in-depth knowledge and experience are instrumental in developing and executing our cybersecurity strategies. Our Senior Vice President of Information Technology tests our compliance with standards, remediates known risks and leads our employee training program. +Reporting to the Board +The Senior Vice President of Information Technology regularly informs the Chief Executive Officer and COO of all aspects related to cybersecurity risks and incidents. This ensures that the highest levels of management are kept abreast of the cybersecurity posture and potential risks facing the Company. Furthermore, significant cybersecurity matters and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues. +Monitor Cybersecurity Incidents +The Senior Vice President of Information Technology monitors the latest developments in cybersecurity, including potential threats and innovative risk management techniques. The Senior Vice President of Information Technology implements and oversees processes for the regular monitoring of our information systems. This includes the deployment of advanced security measures and regular system audits to identify potential vulnerabilities. In the event of a cybersecurity incident, the Senior Vice President of Information Technology is equipped with an incident response plan. This plan includes immediate actions to mitigate the impact and long-term strategies for remediation and prevention of future incidents. +Item 2. Properties. +68 +Table of Contents +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows. +Item 4. Mine Safety Disclosures. +Not applicable. +69 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 20, 2024, we had 119,519,883 shares of common stock outstanding held by approximately 350 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Dividends +In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2023. +Equity Compensation Plan Information +Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1)(2)(3) +830,377 $ 19.11 8,422,916 +Equity compensation plans not approved by security holders — — — +Total 830,377 $ 19.11 8,422,916 +__________________ +(1) Our Board has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). +(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report. +(3) The Matador Resources Company 2022 Employee Stock Purchase Plan (the “ESPP”) was adopted by our Board in April 2022 and approved by our shareholders on June 10, 2022. For a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report. +70 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2018 through December 31, 2023, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before, on, or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +71 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2023, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2023 to October 31, 2023 373 $ 61.88 — — +November 1, 2023 to November 30, 2023 — — — — +December 1, 2023 to December 31, 2023 394 55.93 — — +Total +767 $ 58.82 — — +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +72 +Table of Contents +Item 6. Selected Financial Data. +Not applicable. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +For a comparison of our results of operations for the years ended December 31, 2022 and December 31, 2021, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on March 1, 2023. +Overview +We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +2023 Operational Highlights +We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2023 of $1.16 billion, which was below our estimated range for 2023 D/C/E capital expenditures of $1.18 to $1.32 billion as provided on February 21, 2023, and was in the middle of the revised estimated range of $1.10 to $1.22 billion, as provided on July 25, 2023. +During the year ended December 31, 2023, we completed and began producing oil and natural gas from 119 gross (94.0 net) operated and 103 gross (5.6 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells and one gross (0.4 net) non-operated South Texas well that began producing in 2023. +Substantially all of our 2023 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Advance Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. +73 +Table of Contents +Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022. Our average daily oil production in 2023 was 75,457 Bbl of oil per day, an increase of 26%, as compared to 60,119 Bbl of oil per day in 2022. This increase in oil production was primarily a result of the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf per day, an increase of 24%, as compared to 272.1 MMcf per day in 2022. This increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for each of the years ended December 31, 2023 and 2022. +For the year ended December 31, 2023, our oil and natural gas revenues were $2.55 billion, a decrease of 12% from oil and natural gas revenues of $2.91 billion for the year ended December 31, 2022. Our oil revenues increased 1% to $2.14 billion, as compared to $2.11 billion for the year ended December 31, 2022. The increase in oil revenues resulted from the 26% increase in our oil production noted above, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. Our natural gas revenues decreased 49% to $400.7 million, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $3.25 per Mcf in 2023, as compared to $7.98 per Mcf in 2022, which was partially offset by the 24% increase in natural gas production for the year ended December 31, 2023 noted above. +We reported net income attributable to Matador shareholders of approximately $846.1 million, or $7.05 per diluted common share, on a GAAP basis for the year ended December 31, 2023, as compared to a net income of $1.21 billion, or $10.11 per diluted common share, for the year ended December 31, 2022. Adjusted EBITDA for the year ended December 31, 2023 was $1.85 billion, as compared to Adjusted EBITDA of $2.13 billion for the year ended December 31, 2022. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” +At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of $9.13 billion. Our estimated total proved reserves of 460.1 million BOE at December 31, 2023 represented a 29% year-over-year increase, as compared to 356.7 million BOE at December 31, 2022. Our estimated proved oil reserves were 272.3 million Bbl at December 31, 2023, an increase of 39%, as compared to 196.3 million Bbl at December 31, 2022, and our estimated proved natural gas reserves were 1.13 Tcf at December 31, 2023, an increase of 17%, as compared to 962.6 Bcf at December 31, 2022. Proved oil reserves comprised 59% of our total proved reserves at December 31, 2023, as compared to 55% at December 31, 2022. At December 31, 2023, 63% of our total proved reserves were proved developed reserves, as compared to 62% at December 31, 2022. +Our proved oil and natural gas reserves in the Delaware Basin increased 31% to 452.6 million BOE at December 31, 2023, as compared to 346.8 million BOE at December 31, 2022, primarily as a result of the Advance Acquisition and our ongoing delineation and development operations there. At December 31, 2023, approximately 98% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 40% to 270.1 million Bbl at December 31, 2023, as compared to 193.5 million Bbl at December 31, 2022, and our proved natural gas reserves in the Delaware Basin increased 19% to 1.09 Tcf, as compared to 919.7 Bcf at December 31, 2022. Proved oil reserves comprised 60% of our Delaware Basin total proved reserves at December 31, 2023, as compared to 56% at December 31, 2022. +At both December 31, 2023 and December 31, 2022, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.” +74 +Table of Contents +2023 Midstream Highlights +San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. Volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2023 and 2022. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. +During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. +At December 31, 2023, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included the Marlan Processing Plant, three compressor stations and approximately 70 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico, spanning from the northeastern portion of the Arrowhead asset area into the Ranger asset area. Pronto has also contracted to construct an additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities to be located near the Marlan Processing Plant. +2024 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our 2024 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2024, including 99% with anticipated completed lateral lengths of one mile or greater. +75 +Table of Contents +At December 31, 2023, we had $52.7 million in cash (excluding restricted cash) and $772.6 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $1.325 billion). We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. +As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024. +76 +Table of Contents +Revenues +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2023 2022 2021 +Operating Data: +Revenues (in thousands): (1) +Oil $ 2,144,894 $ 2,113,606 $ 1,205,608 +Natural gas 400,705 792,132 494,934 +Total oil and natural gas revenues 2,545,599 2,905,738 1,700,542 +Third-party midstream services revenues 122,153 90,606 75,499 +Sales of purchased natural gas 149,869 200,355 86,034 +Realized loss on derivatives (9,575) (157,483) (220,105) +Unrealized (loss) gain on derivatives (1,261) 18,809 21,011 +Total revenues $ 2,806,785 $ 3,058,025 $ 1,662,981 +Net Production Volumes: (1) +Oil (MBbl) 27,542 21,943 17,840 +Natural gas (Bcf) 123.4 99.3 81.7 +Total oil equivalent (MBOE) (2) +48,112 38,495 31,454 +Average daily production (BOE/d) (2) +131,813 105,465 86,176 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 77.88 $ 96.32 $ 67.58 +Oil, with realized derivatives (per Bbl) $ 77.88 $ 92.87 $ 56.70 +Natural gas, without realized derivatives (per Mcf) $ 3.25 $ 7.98 $ 6.06 +Natural gas, with realized derivatives (per Mcf) $ 3.17 $ 7.15 $ 5.74 +________________ +(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022 +Oil and natural gas revenues . Our oil and natural gas revenues decreased $360.1 million, or 12%, to $2.55 billion for the year ended December 31, 2023, as compared to $2.91 billion for the year ended December 31, 2022. Our oil revenues increased $31.3 million, or 1%, to $2.14 billion for the year ended December 31, 2023, as compared to $2.11 billion for the year ended December 31, 2022. This increase in oil revenues resulted from a 26% increase in our oil production to 27.5 million Bbl of oil for the year ended December 31, 2023, as compared to 21.9 million Bbl of oil for the year ended December 31, 2022, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. The increase in oil production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $391.4 million, or 49%, to $400.7 million for the year ended December 31, 2023, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues was primarily attributable to the 59% decrease in the weighted average natural gas price realized for the year ended December 31, 2023 to $3.25 per Mcf, as compared to $7.98 per Mcf realized for the year ended December 31, 2022, which was partially offset by a 24% increase in our natural gas production to 123.4 Bcf for the year ended December 31, 2023, as compared to 99.3 Bcf for the year ended December 31, 2022. The increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. +Third-party midstream services revenues. Our third-party midstream services revenues increased $31.5 million, or 35%, to $122.2 million for the year ended December 31, 2023, as compared to $90.6 million for the year ended December 31, 2022. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $65.9 million for the year ended December 31, 2023, as compared to $45.1 million for the year ended December 31, 2022, which includes $15.9 million associated with operating our Pronto midstream assets for the year ended December 31, 2023, as compared to $4.4 million for the year ended December 31, 2022, and (ii) an increase in third-party produced water disposal revenues to $45.3 million for the year ended December 31, 2023, as compared to $35.6 million for the year ended December 31, 2022. +77 +Table of Contents +Sales of purchased natural gas. Our sales of purchased natural gas decreased $50.5 million, or 25%, to $149.9 million for the year ended December 31, 2023, as compared to $200.4 million for the year ended December 31, 2022. This decrease was primarily the result of the 65% decrease in realized natural gas prices, which was partially offset by a 117% increase in natural gas volumes sold during the year ended December 31, 2023. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income. +Realized loss on derivatives . Our realized net loss on derivatives was $9.6 million for the year ended December 31, 2023, as compared to a realized net loss of approximately $157.5 million for the year ended December 31, 2022. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized a net loss of approximately $81.7 million related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net loss of $73.9 million related to our oil costless collar contracts for the year ended December 31, 2022, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts. We realized a net loss of $1.9 million from our oil basis differential swap contracts for the year ended December 31, 2022, resulting from oil basis differentials that were above the fixed prices of certain of our oil basis differential swap contracts. We realized an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023, as compared to an average loss on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022. Our total natural gas volumes hedged represented 2% and 61% of our total natural gas production for the years ended December 31, 2023 and 2022, respectively. +Unrealized (loss) gain on derivatives . Our unrealized loss on derivatives was approximately $1.3 million for the year ended December 31, 2023, as compared to an unrealized gain of $18.8 million for the year ended December 31, 2022. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas derivatives and oil basis differential swap contracts changed from a net liability of approximately $14.9 million to a net asset of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the year ended December 31, 2022. +78 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2023 2022 2021 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing $ 264,493 $ 282,193 $ 178,987 +Lease operating 243,655 157,105 108,964 +Plant and other midstream services operating 128,910 95,522 61,459 +Purchased natural gas 129,401 178,937 77,126 +Depletion, depreciation and amortization 716,688 466,348 344,905 +Accretion of asset retirement obligations 3,943 2,421 2,068 +General and administrative 110,373 116,229 96,396 +Total expenses 1,597,463 1,298,755 869,905 +Operating income 1,209,322 1,759,270 793,076 +Other income (expense): +Net loss on asset sales and impairment (202) (1,311) (331) +Interest expense (121,520) (67,164) (74,687) +Other income (expense) 8,785 (5,121) (2,712) +Total other expense (112,937) (73,596) (77,730) +Income before income taxes 1,096,385 1,685,674 715,346 +Income tax provision (benefit) +Current 13,922 54,877 — +Deferred 172,104 344,480 74,710 +Total income tax provision 186,026 399,357 74,710 +Net income attributable to non-controlling interest in subsidiaries (64,285) (72,111) (55,668) +Net income attributable to Matador Resources Company shareholders $ 846,074 $ 1,214,206 $ 584,968 +Expenses per BOE: +Production taxes, transportation and processing $ 5.50 $ 7.33 $ 5.69 +Lease operating $ 5.06 $ 4.08 $ 3.46 +Plant and other midstream services operating $ 2.68 $ 2.48 $ 1.95 +Depletion, depreciation and amortization $ 14.90 $ 12.11 $ 10.97 +General and administrative $ 2.29 $ 3.02 $ 3.06 +Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022 +Production taxes, transportation and processing. Our production taxes and transportation and processing expenses decreased $17.7 million, or 6%, to $264.5 million for the year ended December 31, 2023, as compared to $282.2 million for the year ended December 31, 2022. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 25% to $5.50 per BOE for the year ended December 31, 2023, as compared to $7.33 per BOE for the year ended December 31, 2022. These decreases were primarily attributable to the $22.7 million decrease in our production taxes to $200.2 million for the year ended December 31, 2023, as compared to $222.9 million for the year ended December 31, 2022, resulting from the $360.1 million decrease in oil and natural gas revenues for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the $5.0 million increase in transportation and processing expenses to $64.3 million for the year ended December 31, 2023, as compared to $59.3 million for the year ended December 31, 2022, primarily resulting from the 25% increase in total oil equivalent production between the respective periods. +Lease operating expenses. Our lease operating expenses increased $86.6 million, or 55%, to $243.7 million for the year ended December 31, 2023, as compared to $157.1 million for the year ended December 31, 2022. On a unit-of-production basis, our lease operating expenses increased 24% to $5.06 per BOE for the year ended December 31, 2023, as compared to $4.08 per BOE for the year ended December 31, 2022. These increases for the year ended December 31, 2023 were primarily attributable to the increased number of wells being operated by us, including 127 wells from the Advance Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2023, as compared to the year ended December 31, 2022. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $33.4 million, or 35%, to $128.9 million for the year ended December 31, 2023, as compared to $95.5 million for the year ended December 31, 2022. This increase was primarily attributable to increased throughput volumes at San Mateo and Pronto +79 +Table of Contents +from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations of $36.7 million for the year ended December 31, 2023, as compared to $24.9 million for the year ended December 31, 2022, (ii) increased expenses associated with our commercial produced water disposal operations of $53.6 million for the year ended December 31, 2023, as compared to $46.5 million for the year ended December 31, 2022, and (iii) increased expenses in connection with operating our Pronto midstream assets of $18.3 million for the year ended December 31, 2023, which assets were purchased on June 30, 2022, as compared to $8.3 million for the year ended December 31, 2022. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $250.3 million, or 54%, to $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and a 25% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 23% to $14.90 per BOE for the year ended December 31, 2023, as compared to $12.11 per BOE for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and an increase in actual costs and estimated future costs to drill, complete and equip our wells between the two periods. +General and administrative. Our general and administrative expenses decreased $5.9 million, or 5%, to $110.4 million for the year ended December 31, 2023, as compared to $116.2 million for the year ended December 31, 2022. Our general and administrative expenses on a unit-of-production basis decreased 24% to $2.29 per BOE for the year ended December 31, 2023, as compared to $3.02 per BOE for the year ended December 31, 2022, primarily as a result of the 25% increase in our total oil equivalent production between the two periods. +Interest expense. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. For the year ended December 31, 2022, we incurred total interest expense of approximately $77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. The increase in interest expense for the year ended December 31, 2023 is a result of borrowings under the Credit Agreement that were used in connection with the Advance Acquisition, borrowings under the San Mateo Credit Facility, the issuance of the 2028 Notes in April 2023 and the significant increase in interest rates between the two periods. +Total income tax provision. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a current income tax provision of $54.9 million and a deferred income tax provision of $344.5 million for the year ended December 31, 2022. Our effective income tax rate of 25% for the year ended December 31, 2022 differed from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and state taxes, primarily in New Mexico. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue during 2024 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. In April 2023, we closed the Initial Advance Acquisition that was funded through a combination of cash on hand and borrowings under our Credit Agreement. In addition, on April 11, 2023, we issued and sold $500.0 million in aggregate principal amount of 2028 Notes. We used the net proceeds from the sale of the 2028 Notes of approximately $487.6 million, after deducting the initial purchasers’ discounts and estimated offering expenses, to partially repay borrowings under our Credit Agreement. We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. +At December 31, 2023, we had cash totaling $52.7 million and restricted cash totaling $53.6 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +80 +Table of Contents +At December 31, 2023, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the “2026 Notes”), (ii) $500.0 million of outstanding 2028 Notes, (iii) $500.0 million of borrowings outstanding under the Credit Agreement and (iv) approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. +In March 2023, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.25 billion, (ii) increase the elected borrowing commitment from $775.0 million to $1.25 billion and (iii) maintain the maximum facility amount at $1.50 billion. This March 2023 redetermination constituted the regularly scheduled May 1 redetermination. +In October 2023, the lenders under our Credit Agreement completed their review of the our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) increase the borrowing base from $2.25 billion to $2.50 billion, (ii) increase the elected borrowing commitment from $1.25 billion to $1.325 billion and (iii) increase the maximum facility amount from $1.50 billion to $2.00 billion. This October 2023 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). The Credit Agreement matures October 31, 2026. +The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2023. +At December 31, 2023, San Mateo had $522.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In October 2023, the lenders under the San Mateo Credit Facility increased the lender commitments from $485.0 million to $535.0 million. The San Mateo Credit Facility matures December 9, 2026. +The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2023. +In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2024 operating seven contracted drilling rigs in the Delaware Basin and added an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and the Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware +81 +Table of Contents +Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells, including 99% with anticipated completed lateral lengths of greater than one mile. +As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024. +Our 2024 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2024 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2024 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +82 +Table of Contents +Our cash flows for the years ended December 31, 2023, 2022 and 2021 are presented below. +Year Ended December 31, +2023 2022 2021 +(In thousands) +Net cash provided by operating activities $ 1,867,828 $ 1,978,739 $ 1,053,355 +Net cash used in investing activities (3,211,192) (1,037,477) (729,265) +Net cash provided by (used in) financing activities 902,332 (480,852) (328,553) +Net change in cash $ (441,032) $ 460,410 $ (4,463) +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ 1,849,547 $ 2,127,156 $ 1,051,973 +__________________ +(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. +Cash Flows Provided by Operating Activities +Net cash provided by operating activities decreased by $110.9 million to $1.87 billion for the year ended December 31, 2023, as compared to net cash provided by operating activities of $1.98 billion for the year ended December 31, 2022. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $1.82 billion for the year ended December 31, 2023 from $2.10 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the 25% increase in total oil equivalent production during 2023, as compared to 2022. Changes in our operating assets and liabilities between December 31, 2022 and December 31, 2023 resulted in a net increase of approximately $168.0 million in net cash provided by operating activities for the year ended December 31, 2023, as compared to the year ended December 31, 2022. +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +Cash Flows Used in Investing Activities +Net cash used in investing activities increased by $2.17 billion to $3.21 billion for the year ended December 31, 2023 from $1.04 billion for the year ended December 31, 2022. This increase in net cash used in investing activities was primarily due to (i) an increase between the periods of $1.68 billion in expenditures related to the Advance Acquisition, (ii) an increase between the periods of $421.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin and (iii) an increase between the periods of $85.7 million in midstream capital expenditures. These increases were partially offset by a decrease of $75.8 million related to the Pronto Acquisition in 2022. +Cash Flows Provided by (Used in) Financing Activities +Net cash provided by financing activities increased $1.38 billion to $902.3 million for the year ended December 31, 2023, from net cash used in financing activities of $480.9 million for the year ended December 31, 2022. During the year ended December 31, 2023, our net cash provided by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million. During the year ended December 31, 2022, our net cash used in financing activities was primarily attributable to (i) the repurchase of an aggregate principal of $350.8 million of the 2026 Notes for $344.3 million, (ii) net repayments under our Credit Agreement of $100.0 million, (iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $57.7 million and (iv) dividends paid of $35.2 million, which were partially offset by net borrowings under the San Mateo Credit Facility of $80.0 million. +83 +Table of Contents +See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2026 Notes and the 2028 Notes. +Guarantor Financial Information +As of December 31, 2023, Matador’s outstanding senior notes registered under the Securities Act consisted of the 2026 Notes. The 2026 Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2023, the Guarantor Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a Guarantor Subsidiary of the 2026 Notes. +The following tables present summarized financial information of Matador (as issuer of the 2026 Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities. +(in thousands) +Summarized Balance Sheet December 31, 2023 +Assets +Current assets $ 619,716 +Net property and equipment $ 5,867,130 +Other long-term assets $ 64,759 +Liabilities +Current liabilities $ 684,159 +Long-term debt $ 1,684,627 +Other long-term liabilities $ 701,153 +(in thousands) Year Ended +Summarized Statement of Income December 31, 2023 +Revenues $ 2,550,755 +Expenses 1,499,363 +Operating income $ 1,051,392 +Other expense (80,325) +Tax provision (186,026) +Net income $ 785,041 +Non-GAAP Financial Measures +We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and +84 +Table of Contents +assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively. +Year Ended December 31, +2023 2022 2021 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income: +Net income attributable to Matador Resources Company shareholders $ 846,074 $ 1,214,206 $ 584,968 +Net income attributable to non-controlling interest in subsidiaries 64,285 72,111 55,668 +Net income 910,359 1,286,317 640,636 +Interest expense 121,520 67,164 74,687 +Total income tax provision 186,026 399,357 74,710 +Depletion, depreciation and amortization 716,688 466,348 344,905 +Accretion of asset retirement obligations 3,943 2,421 2,068 +Unrealized loss (gain) on derivatives 1,261 (18,809) (21,011) +Non-cash stock-based compensation expense 13,661 15,123 9,039 +Net loss on impairment 202 1,311 331 +(Income) expense related to contingent consideration and other (6,038) 4,926 1,485 +Consolidated Adjusted EBITDA 1,947,622 2,224,158 1,126,850 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (98,075) (97,002) (74,877) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 1,849,547 $ 2,127,156 $ 1,051,973 +Year Ended December 31, +2023 2022 2021 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities: +Net cash provided by operating activities $ 1,867,828 $ 1,978,739 $ 1,053,355 +Net change in operating assets and liabilities (50,027) 117,935 982 +Interest expense, net of non-cash portion 114,473 63,064 71,028 +Current income tax provision 13,922 54,877 — +Other non-cash and non-recurring expense 1,426 9,543 1,485 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (98,075) (97,002) (74,877) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 1,849,547 $ 2,127,156 $ 1,051,973 +For the year ended December 31, 2023, we reported net income attributable to Matador shareholders of $846.1 million, as compared to $1.21 billion for the year ended December 31, 2022. This decrease primarily resulted from lower realized oil and natural gas prices, partially offset by higher oil and natural gas production, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. In addition, we had increased depletion, depreciation and amortization expenses of $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, and increased interest expense of $121.5 million for the year ended December 31, 2023, as compared to $67.2 million for the year ended December 31, 2022. This was partially offset by an income tax provision of $186.0 million for the year ended December 31, 2023, as compared to an income tax provision of $399.4 million for the year ended December 31, 2022. +Adjusted EBITDA, a non-GAAP financial measure, decreased $277.6 million to $1.85 billion for the year ended December 31, 2023, as compared to $2.13 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices, partially offset by higher oil and natural gas production noted above for the year ended December 31, 2023, as compared to the year ended December 31, 2022. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2023, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the +85 +Table of Contents +Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2023. +Payments Due by Period +Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years +(In thousands) +Contractual Obligations: +Borrowings, including letters of credit (1) +$ 1,083,317 $ — $ 1,083,317 $ — $ — +Senior unsecured notes (2) +1,199,191 — 699,191 500,000 — +Office leases 10,229 4,385 5,844 — — +Non-operated drilling commitments (3) +27,946 27,946 — — — +Drilling rig contracts (4) +22,226 21,742 484 — — +Asset retirement obligations (5) +92,090 4,605 4,220 2,376 80,889 +Transportation, gathering, processing and disposal agreements with non-affiliates (6) +546,023 78,563 164,709 132,073 170,678 +Transportation, gathering, processing and disposal agreements with San Mateo (7) +218,185 — 110,719 107,466 — +Midstream contracts (8) +162,692 109,979 52,713 — — +Total contractual cash obligations $ 3,361,899 $ 247,220 $ 2,121,197 $ 741,915 $ 251,567 +__________________ +(1) The amounts included in the table above represent principal maturities only. At December 31, 2023, we had $500.0 million in borrowings outstanding under the Credit Agreement and approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures October 31, 2026. At December 31, 2023 San Mateo had $522.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures December 9, 2026. Assuming the amounts outstanding and interest rates of 7.21% and 7.71%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2023, the interest expense for such facilities is expected to be approximately $36.6 million and $40.8 million, respectively, each year until maturity. +(2) The amounts included in the table above represent principal maturities only. Interest expense on the $699.2 million of outstanding 2026 Notes as of December 31, 2023 is expected to be approximately $41.1 million each year until maturity. Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2023 is expected to be approximately $34.4 million each year until maturity. +(3) At December 31, 2023, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. +(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2023. +(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments. +(7) We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(8) At December 31, 2023, we had outstanding commitments related to the construction and installation of Pronto’s additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase 11 compressors to be utilized in San Mateo and Pronto operations. +86 +Table of Contents +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, political instability in China, military conflict and political instability in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. +The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +For the year ended December 31, 2023, oil prices averaged $77.60 per Bbl, as compared to $94.33 per Bbl in 2022, ranging from a low of $66.74 per Bbl in mid-March to a high of $93.68 per Bbl in late September, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $77.88 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2023, as compared to $96.32 per Bbl ($92.87 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2022. At February 20, 2024, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2023, closing at $78.18 per Bbl, and was also higher compared to $76.34 per Bbl on February 17, 2023. +Natural gas prices decreased significantly during 2023. For the year ended December 31, 2023, natural gas prices averaged $2.66 per MMBtu, as compared to $6.54 per MMBtu in 2022, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2023, natural gas prices ranged from a high of $4.17 per MMBtu in early January to a low of $1.99 per MMBtu in late March. As a result of milder-than-expected winter weather and high storage levels, natural gas prices declined over the course of the fourth quarter of 2023, finishing the year at $2.51 per MMBtu. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were also lower in 2023 as compared to 2022, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2023. We realized a weighted average natural gas price of $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2023, as compared to $7.98 per Mcf ($7.15 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2022. At February 20, 2024, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased further from year-end 2023, closing at $1.58 per MMBtu, and was also lower as compared to $2.28 per MMBtu at February 17, 2023. +The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2023, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas. +The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 20, 2024, this oil price differential was approximately +$1.64 per Bbl. At February 20, 2024, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2024. +Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase, particularly beginning in the latter half of 2022 and into 2023. As a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($1.00) per MMBtu for the year ended December 31, 2023. Between December 31, 2023 and February 20, 2024, this natural gas price differential narrowed to approximately ($0.80) per MMBtu. A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2022 and 2023, we typically realized a narrower +87 +Table of Contents +differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 8% of our reported natural gas production for the year ended December 31, 2023 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2023, we incurred realized losses on our natural gas basis differential derivative contracts of approximately $9.6 million resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. At December 31, 2023, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in each of 2024 and 2025. +We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any material interruptions with produced water disposal, takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have experienced historically, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. +As a result of the increases in oil prices during 2022 and 2023, we have at times experienced inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices remain at their current levels or increase, we may be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows. +We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. At February 20, 2024, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2024 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2024. We could be subject to the CAMT in future years, which would require us to pay minimum cash tax payments of 15% of annual adjusted pretax book income. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream +88 +Table of Contents +operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has implemented similar rules and regulations. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +In January 2021, President Biden signed an executive order instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices, which has lapsed. In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico. In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making. The BLM indicated that the Lease Sale Litigation or the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. The impact of federal actions and lawsuits related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well. +Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth”. +89 +Table of Contents +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2023. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. +90 +Table of Contents +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” +Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Purchase Accounting +Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023. +In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts. The most significant assumptions relate to the estimated fair values of oil and natural gas properties. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of future production volumes, estimates of future commodity prices, expected development and operating costs, an estimate of a market-based weighted average cost of capital rate and recent market comparable transactions for unproved acreage. +Recent Accounting Pronouncements +See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. +91 +Table of Contents +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option or options have different fixed price components. When the settlement price is below the price floor established by the collar, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil, natural gas or NGL volume. When the settlement price is above the price ceiling established by the costless collar, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil, natural gas or NGL volume. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2023, Bank of America was the counterparty for our derivative instruments. We have considered the credit standing of the counterparty in determining the fair value of our derivative financial instruments. +At December 31, 2023, we had natural gas basis differential swap contracts open and in place to mitigate our exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. +See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors—Risks Related to Laws and Regulations—Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt. At December 31, 2023, we had $500.0 million of outstanding borrowings under our Credit Agreement at an interest rate of 7.21%, $699.2 million of outstanding 2026 Notes at a coupon rate of 5.875%, $500.0 million of outstanding 2028 Notes at a coupon rate of 6.875% and $522.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 7.71%. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo and Pronto are subject to the credit risk of their customers. The inability or failure of our, San Mateo’s or Pronto’s significant customers to meet their obligations or their +92 +Table of Contents +insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparty on our derivative financial instruments in place at February 20, 2024 was Bank of America, which is also a lender (or affiliate thereof) under our Credit Agreement. +Impact of inflation . Inflation in the United States has become much more significant in recent years. We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward. We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors—Risks Related to our Financial Condition—Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected” and “Risk Factors—Risks Related to our Operations—The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report beginning on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2023, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +93 +Table of Contents +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2023 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +94 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 27, 2024 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 27, 2024 +95 +Table of Contents +Item 9B. Other Information. +During the three months ended December 31, 2023, no director or officer (as defined in Rule 16a-1(f) under the Exchange Act) of the Company adopted , modified or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2024 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 4—Ratification of Appointment of KPMG LLP.” +96 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2023 and 2022, Consolidated Statements of Income for the Years Ended December 31, 2023, 2022 and 2021, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021. +2. Financial Statement Schedules : All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto. +3. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below. +Item 16. Form 10-K Summary. +None. +97 +Table of Contents +EXHIBIT INDEX +Exhibit +Number Description +2.1* +Securities Purchase Agreement, dated January 24, 2023, by and among MRC Hat Mesa, LLC, MRC Energy Company (solely for the limited purposes stated therein), AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 24, 2023). +2.2 +Amendment No. 1 to Securities Purchase Agreement, dated April 5, 2023, by and among MRC Hat Mesa, LLC, AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (filed herewith). +2.3* +Waiver and Release Agreement and Amendment No. 2 to Securities Purchase Agreement, dated December 1, 2023, by and among MRC Hat Mesa, LLC, AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (filed herewith). +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018). +4.3 +First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018). +4.4 +Second Supplemental Indenture, dated as of December 14, 2021, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N. A., as agent for Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on December 14, 2021). +4.5 +Indenture, dated as of April 11, 2023, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 11, 2023). +4.6 +Third Supplemental Indenture, dated as of July 25, 2023, by and among Matador Resources Company, MRC Hat Mesa, LLC, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2023). +4.7 +First Supplemental Indenture, dated as of July 25, 2023, by and among Matador Resources Company, MRC Hat Mesa, LLC, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2023). +4.8 +Description of Capital Stock (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2019). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +98 +Table of Contents +10.2† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.4† +Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013). +10.5† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.6† +Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.7† +First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018). +10.8† +First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.9† +Form of Employment Agreement between Matador Resources Company and each of Michael D. Frenzel, W. Thomas Elsener and Brian J. Willey (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 20, 2022). +10.10† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.11 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.12 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.13 +Fourth Amended and Restated Credit Agreement, dated as of November 18, 2021, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 18, 2021). +10.14 +First Amendment to Fourth Amended and Restated Credit Agreement dated as of April 25, 2022, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2022). +10.15 +Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 31, 2023, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, Royal Bank of Canada, as resigning Administrative Agent, and Truist Bank, as successor Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 3, 2023). +10.16 +Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of April 10, 2023, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Truist Bank, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2023). +10.17 +Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 19, 2023, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Truist Bank, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 19, 2023). +99 +Table of Contents +10.18† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.19† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.20† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.21† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.22† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.23† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.24† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.25† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.26† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.27† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.28† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.29† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.30† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.31† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.32† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.33† +Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019). +10.34† +First Amendment to Matador Resources Company 2019 Long-Term Incentive Plan effective April 21, 1011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 16, 2022). +10.35† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.36† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +100 +Table of Contents +10.37† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.38† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.39† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.58 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.40† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.41† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan with ratable vesting for employees without employment agreements (incorporated by reference to Exhibit 10.60 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.42† +Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the year ended December 31, 2020). +10.43† +Matador Resources Company 2022 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 16, 2022). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +22.1 +List of Subsidiary Guarantors (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc. (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +97 +Matador Resources Company Clawback Policy (filed herewith) . +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2023, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +104 Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101). +† Indicates a management contract or compensatory plan or arrangement. +* This filing excludes certain schedules and exhibits pursuant to Item 601(a)(5) of Regulation S-K, which the Company agrees to furnish supplementally to the SEC upon request; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished. +101 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +February 27, 2024 By: /s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature Title Date +/s/ Joseph Wm. Foran Chairman and Chief Executive Officer February 27, 2024 +Joseph Wm. Foran (Principal Executive Officer) +/s/ Brian J. Willey Executive Vice President and Chief Financial Officer February 27, 2024 +Brian J. Willey (Principal Financial Officer) +/s/ Robert T. Macalik Executive Vice President and Chief Accounting Officer February 27, 2024 +Robert T. Macalik (Principal Accounting Officer) +/s/ Shelley F. Appel Director February 27, 2024 +Shelley F. Appel +/s/ Reynald A. Baribault Director February 27, 2024 +Reynald A. Baribault +/s/ R. Gaines Baty Director February 27, 2024 +R. Gaines Baty +/s/ William M. Byerley Director February 27, 2024 +William M. Byerley +/s/ Monika U. Ehrman Director February 27, 2024 +Monika U. Ehrman +/s/ Julia P. Forrester Rogers Director February 27, 2024 +Julia P. Forrester Rogers +/s/ James M. Howard Director February 27, 2024 +James M. Howard +/s/ Timothy E. Parker Director February 27, 2024 +Timothy E. Parker +/s/ Kenneth L. Stewart Director February 27, 2024 +Kenneth L. Stewart +/s/ Susan M. Ward Director February 27, 2024 +Susan M. Ward +102 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water. +Bcf . One billion cubic feet of natural gas. +Bench . A geologic zone or formation or a subdivision of a geologic formation. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Central delivery point or CDP . The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Developed oil and natural gas reserves . Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. +Development well . A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differential . The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. +Dry hole . A well found to be incapable of producing hydrocarbons. +Economically producible . As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. +ESP . Electric submersible pump. +Exploratory well . A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well. +Extension well . A well drilled to extend the limits of a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the +103 +Table of Contents +assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +GAAP, or U.S. GAAP . United States, generally accepted accounting principles. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Lateral length . Length of the drilled or completed portion of a horizontal well. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or produced water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Organization of Petroleum Exporting Countries or OPEC . An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid. +OPEC+ . A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +104 +Table of Contents +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recovered than probable reserves. +Probable reserves . Additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Production costs . Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining such wells and related equipment and facilities. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Prospectivity . Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation. +Proved area . The part of a property to which proved reserves have been specifically attributed. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved properties . Properties with proved reserves. +Proved reserves . The quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Reasonable certainty. A high degree of confidence that the quantities of oil and/or natural gas will be recovered. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +105 +Table of Contents +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Service well. A well drilled or completed for the purpose of supporting production in an existing field. +Spud . The act of beginning to drill an oil or natural gas well. +Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to specific geologic condition. +Tcf . One trillion cubic feet of natural gas. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserves analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +WTI . West Texas Intermediate. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +106 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2023, 2022 and 2021 +Index +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2023 and 2022 +F-5 +Consolidated Statements of Income for the Years Ended December 31, 2023, 2022 and 2021 +F-6 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 +F-7 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 +F- 8 +Notes to Consolidated Financial Statements +F- 9 +Unaudited Supplementary Information +F- 42 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2024 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation +As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. +F-2 +Table of Contents +For the year ended December 31, 2023, the Company recorded depletion expense of evaluated oil and natural gas properties of $672.0 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company’s consolidated balance sheet includes $9.6 billion of gross evaluated oil and natural gas properties as of December 31, 2023. The Company’s internal reservoir engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reservoir engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company. +We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to future production volumes, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reservoir engineers as well as the external reservoir engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reservoir engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reservoir engineers’ estimate regarding future operating and development costs based on historical actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserves estimates. We recalculated the depletion expense calculation and analyzed it for compliance with industry and regulatory standards. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results. +Fair value measurement of evaluated oil and natural gas properties acquired in the Advance Energy Partners business combination +As discussed in Note 6 to the consolidated financial statements, on April 12, 2023, the Company completed the acquisition of Advance Energy Partners. As a result of the transaction, the Company acquired evaluated oil and natural gas properties with an acquisition-date fair value of $1.4 billion. The acquisition was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed at their estimated fair values as of the acquisition date, with any excess purchase price allocated to goodwill. The fair value of evaluated oil and natural gas properties were measured using the discounted cash flow method. Inputs to the valuation of evaluated oil and natural gas properties include estimates of future production volumes, expected operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. +We identified the evaluation of the fair value measurement of the evaluated oil and natural gas properties acquired in the Advance Energy Partners transaction as a critical audit matter. There was a high degree of subjective auditor judgment in evaluating management’s key assumptions used to estimate the fair value of such properties. Specifically, these key assumptions included future production volumes, expected operating and development costs, future commodity prices, and a market-based weighted average cost of capital rate as changes to these key assumptions could have had a significant impact on the determination of the fair value. Additionally, the audit effort associated with evaluating the future commodity prices and market-based weighted average cost of capital required specialized skills and knowledge. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s acquisition-date valuation process, including controls over the determination of the key assumptions, as listed above, used to measure the initial fair value of the acquired evaluated oil and natural gas properties. We evaluated (1) the professional qualifications of the Company’s internal and external reservoir engineers and the external engineering firm, (2) the knowledge, skills, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We assessed compliance of the methodology used by the Company’s internal and external reservoir engineers to estimate evaluated oil and natural gas reserves with industry +F-3 +Table of Contents +and regulatory standards. We compared the estimated future evaluated production volumes used by the Company to historical Advance Energy Partners production volumes. We evaluated the expected operating and developmental cost assumptions used by the internal reservoir engineers to estimate future cash flows by comparing them to Advance Energy Partner’s historical costs and to future operating and developmental cost assumptions used by the Company for its comparable assets operated in the same area. We tested the relevant basis differentials that were applied to the future commodity price assumptions by comparing to historical realized basis differentials from both Advance Energy Partners and the Company. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating: +• the future commodity price assumptions by comparing to an independently developed range of forward price estimates from analysts and other industry sources +• the market-based weighted average cost of capital rate by comparing it against a range that was independently developed using publicly available market data for comparable entities. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +February 27, 2024 +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2023 2022 +ASSETS +Current assets +Cash $ 52,662 $ 505,179 +Restricted cash 53,636 42,151 +Accounts receivable +Oil and natural gas revenues 274,192 224,860 +Joint interest billings 163,660 180,947 +Other 35,102 48,011 +Derivative instruments 2,112 3,930 +Lease and well equipment inventory 41,808 15,184 +Prepaid expenses and other current assets 92,700 51,570 +Total current assets 715,872 1,071,832 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated 9,633,757 6,862,455 +Unproved and unevaluated 1,193,257 977,502 +Midstream properties 1,318,015 1,057,668 +Other property and equipment 40,375 32,847 +Less accumulated depletion, depreciation and amortization ( 5,228,963 ) ( 4,512,275 ) +Net property and equipment 6,956,441 4,418,197 +Other assets +Derivative instruments 558 — +Other long-term assets 54,125 64,476 +Total other assets 54,683 64,476 +Total assets $ 7,726,996 $ 5,554,505 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable $ 68,185 $ 58,848 +Accrued liabilities 365,848 261,310 +Royalties payable 161,983 117,698 +Amounts due to affiliates 28,688 32,803 +Advances from joint interest owners 19,954 52,357 +Other current liabilities 40,617 52,857 +Total current liabilities 685,275 575,873 +Long-term liabilities +Borrowings under Credit Agreement 500,000 — +Borrowings under San Mateo Credit Facility 522,000 465,000 +Senior unsecured notes payable 1,184,627 695,245 +Asset retirement obligations 87,485 52,985 +Deferred income taxes 581,439 428,351 +Other long-term liabilities 38,482 19,960 +Total long-term liabilities 2,914,033 1,661,541 +Commitments and contingencies (Note 14) +Shareholders’ equity +Common stock — $ 0.01 par value, 160,000,000 shares authorized; 119,478,282 and 118,953,381 shares issued; and 119,458,674 and 118,948,624 shares outstanding, respectively +1,194 1,190 +Additional paid-in capital 2,133,172 2,101,999 +Retained earnings 1,776,541 1,007,642 +Treasury stock, at cost, 19,608 and 4,757 shares, respectively +( 45 ) ( 34 ) +Total Matador Resources Company shareholders’ equity 3,910,862 3,110,797 +Non-controlling interest in subsidiaries 216,826 206,294 +Total shareholders’ equity 4,127,688 3,317,091 +Total liabilities and shareholders’ equity $ 7,726,996 $ 5,554,505 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share data) +Year Ended December 31, +2023 2022 2021 +Revenues +Oil and natural gas revenues $ 2,545,599 $ 2,905,738 $ 1,700,542 +Third-party midstream services revenues 122,153 90,606 75,499 +Sales of purchased natural gas 149,869 200,355 86,034 +Realized loss on derivatives ( 9,575 ) ( 157,483 ) ( 220,105 ) +Unrealized (loss) gain on derivatives ( 1,261 ) 18,809 21,011 +Total revenues 2,806,785 3,058,025 1,662,981 +Expenses +Production taxes, transportation and processing 264,493 282,193 178,987 +Lease operating 243,655 157,105 108,964 +Plant and other midstream services operating 128,910 95,522 61,459 +Purchased natural gas 129,401 178,937 77,126 +Depletion, depreciation and amortization 716,688 466,348 344,905 +Accretion of asset retirement obligations 3,943 2,421 2,068 +General and administrative 110,373 116,229 96,396 +Total expenses 1,597,463 1,298,755 869,905 +Operating income 1,209,322 1,759,270 793,076 +Other income (expense) +Net loss on asset sales and impairment ( 202 ) ( 1,311 ) ( 331 ) +Interest expense ( 121,520 ) ( 67,164 ) ( 74,687 ) +Other income (expense) 8,785 ( 5,121 ) ( 2,712 ) +Total other expense ( 112,937 ) ( 73,596 ) ( 77,730 ) +Income before income taxes 1,096,385 1,685,674 715,346 +Income tax provision (benefit) +Current 13,922 54,877 — +Deferred 172,104 344,480 74,710 +Total income tax provision 186,026 399,357 74,710 +Net income 910,359 1,286,317 640,636 +Net income attributable to non-controlling interest in subsidiaries ( 64,285 ) ( 72,111 ) ( 55,668 ) +Net income attributable to Matador Resources Company shareholders $ 846,074 $ 1,214,206 $ 584,968 +Earnings per common share +Basic $ 7.10 $ 10.28 $ 5.00 +Diluted $ 7.05 $ 10.11 $ 4.91 +Weighted average common shares outstanding +Basic 119,139 118,122 116,999 +Diluted 119,980 120,131 119,163 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2023, 2022 and 2021 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital (Accumulated deficit) retained earnings Treasury Stock Non-controlling interest in subsidiaries +Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2021 116,847 $ 1,169 $ 2,027,069 $ ( 741,705 ) 2 $ ( 3 ) $ 1,286,530 $ 226,495 $ 1,513,025 +Dividends declared ( 0.125 per share) +— — — ( 14,581 ) — — ( 14,581 ) — ( 14,581 ) +Issuance of common stock pursuant to employee stock compensation plan 768 7 ( 7 ) — — — — — — +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 81 1 ( 1 ) — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 12,113 — — — 12,113 — 12,113 +Stock options exercised, net of options forfeited in net share settlements 312 3 ( 4,258 ) — — — ( 4,255 ) — ( 4,255 ) +Restricted stock forfeited — — — — 156 ( 2,621 ) ( 2,621 ) — ( 2,621 ) +Contribution related to formation of San Mateo, net of tax of $ 3.6 million (See Note 11) +— — 45,056 — — — 45,056 — 45,056 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 61,985 ) ( 61,985 ) +Cancellation of treasury stock ( 146 ) ( 1 ) ( 2,380 ) — ( 146 ) 2,381 — — — +Current period net income — — — 584,968 — — 584,968 55,668 640,636 +Balance at December 31, 2021 117,862 1,179 2,077,592 ( 171,318 ) 12 ( 243 ) 1,907,210 220,178 2,127,388 +Dividends declared ( 0.30 per share) +— — — ( 35,246 ) — — ( 35,246 ) — ( 35,246 ) +Issuance of common stock pursuant to employee stock compensation plan 1,001 10 ( 11,544 ) — — — ( 11,534 ) — ( 11,534 ) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 25 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 20,224 — — — 20,224 — 20,224 +Stock options exercised, net of options forfeited in net share settlements 157 2 ( 4,007 ) — — — ( 4,005 ) — ( 4,005 ) +Restricted stock forfeited — — — — 85 ( 2,376 ) ( 2,376 ) — ( 2,376 ) +Contribution related to formation of San Mateo, net of tax of $ 5.9 million (See Note 11) +— — 22,318 — — — 22,318 — 22,318 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 85,995 ) ( 85,995 ) +Cancellation of treasury stock ( 92 ) ( 1 ) ( 2,584 ) — ( 92 ) 2,585 — — — +Current period net income — — — 1,214,206 — — 1,214,206 72,111 1,286,317 +Balance at December 31, 2022 118,953 $ 1,190 $ 2,101,999 $ 1,007,642 5 $ ( 34 ) $ 3,110,797 $ 206,294 $ 3,317,091 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital (Accumulated deficit) retained earnings Treasury Stock Non-controlling interest in subsidiaries Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2023 118,953 $ 1,190 $ 2,101,999 $ 1,007,642 5 $ ( 34 ) $ 3,110,797 $ 206,294 $ 3,317,091 +Dividends declared ($ 0.65 per share) +— — — ( 77,175 ) — — ( 77,175 ) — ( 77,175 ) +Issuance of common stock pursuant to employee stock compensation plan 623 6 ( 15,560 ) — — — ( 15,554 ) — ( 15,554 ) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 11 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 21,580 — — — 21,580 — 21,580 +Stock options exercised, net of options forfeited in net share settlements 22 — 49 — — — 49 — 49 +Restricted stock forfeited — — — — 146 ( 5,087 ) ( 5,087 ) — ( 5,087 ) +Contributions related to formation of San Mateo, net of tax of $ 8.0 million (See Note 11) +— — 30,178 — — — 30,178 — 30,178 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries (See Note 11) — — — — — — — 24,500 24,500 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 78,253 ) ( 78,253 ) +Cancellation of treasury stock ( 131 ) ( 2 ) ( 5,074 ) — ( 131 ) 5,076 — — — +Current period net income — — — 846,074 — — 846,074 64,285 910,359 +Balance at December 31, 2023 119,478 $ 1,194 $ 2,133,172 $ 1,776,541 20 $ ( 45 ) $ 3,910,862 $ 216,826 $ 4,127,688 +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2023 2022 2021 +Operating activities +Net income $ 910,359 $ 1,286,317 $ 640,636 +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized loss (gain) on derivatives 1,261 ( 18,809 ) ( 21,011 ) +Depletion, depreciation and amortization 716,688 466,348 344,905 +Accretion of asset retirement obligations 3,943 2,421 2,068 +Stock-based compensation expense 13,661 15,123 9,039 +Deferred income tax provision 172,104 344,480 74,710 +Amortization of debt issuance cost and other debt related costs 7,047 ( 517 ) 3,659 +Other non-cash changes ( 7,262 ) 1,311 331 +Changes in operating assets and liabilities +Accounts receivable 59,893 ( 205,426 ) ( 98,456 ) +Lease and well equipment inventory ( 3,034 ) ( 2,847 ) ( 1,537 ) +Prepaid expenses and other current assets ( 11,757 ) ( 22,952 ) ( 11,786 ) +Other long-term assets 646 175 56 +Accounts payable, accrued liabilities and other current liabilities 2,810 63,455 76,891 +Royalties payable 34,273 23,339 28,310 +Advances from joint interest owners ( 32,402 ) 34,283 7,018 +Other long-term liabilities ( 402 ) ( 7,962 ) ( 1,478 ) +Net cash provided by operating activities 1,867,828 1,978,739 1,053,355 +Investing activities +Drilling, completion and equipping capital expenditures ( 1,192,800 ) ( 771,830 ) ( 431,136 ) +Acquisition of Advance ( 1,676,132 ) — — +Acquisition of oil and natural gas properties ( 187,655 ) ( 155,074 ) ( 238,609 ) +Midstream capital expenditures ( 165,719 ) ( 80,051 ) ( 63,359 ) +Acquisition of midstream assets — ( 75,816 ) — +Expenditures for other property and equipment ( 3,636 ) ( 1,213 ) ( 376 ) +Proceeds from sale of assets and other 14,750 46,507 4,215 +Net cash used in investing activities ( 3,211,192 ) ( 1,037,477 ) ( 729,265 ) +Financing activities +Repayments of borrowings under Credit Agreement ( 3,032,000 ) ( 300,000 ) ( 600,000 ) +Borrowings under Credit Agreement 3,532,000 200,000 260,000 +Repayments of borrowings under San Mateo Credit Facility ( 171,000 ) ( 150,000 ) ( 84,000 ) +Borrowings under San Mateo Credit Facility 228,000 230,000 135,000 +Cost to enter into or amend credit facilities ( 9,296 ) ( 3,725 ) ( 4,108 ) +Proceeds from issuance of senior unsecured notes 494,800 — — +Issuance costs of senior unsecured notes ( 8,503 ) — — +Purchase of senior unsecured notes — ( 344,302 ) — +Dividends paid ( 77,175 ) ( 35,246 ) ( 14,581 ) +Contributions related to formation of San Mateo 38,200 28,250 48,626 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries 24,500 — — +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries ( 78,253 ) ( 85,995 ) ( 61,985 ) +Taxes paid related to net share settlement of stock-based compensation ( 22,910 ) ( 19,242 ) ( 8,211 ) +Other ( 16,031 ) ( 592 ) 706 +Net cash provided by (used in) financing activities 902,332 ( 480,852 ) ( 328,553 ) +(Decrease) increase in cash and restricted cash ( 441,032 ) 460,410 ( 4,463 ) +Cash and restricted cash at beginning of period 547,330 86,920 91,383 +Cash and restricted cash at end of period $ 106,298 $ 547,330 $ 86,920 +Supplemental disclosures of cash flow information (Note 15) +The accompanying notes are an integral part of these consolidated financial statements. +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2023, 2022 and 2021 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations primarily through its midstream joint venture, San Mateo Midstream, LLC and its subsidiaries (“San Mateo”), and Pronto Midstream, LLC and its subsidiary (“Pronto”) in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquids (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, customers of San Mateo and Pronto or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2023, three significant purchasers accounted for 76 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 42 %), Exxon Mobil Corporation ( 24 %) and Enterprise ( 10 %). For the year ended December 31, 2022, three significant purchasers accounted for 70 % of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation ( 34 %), Plains Marketing, L.P. ( 27 %) and BP America Production Company ( 9 %). For the year ended December 31, 2021, three significant purchasers accounted for 72 % of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation ( 33 %), Plains Marketing, L.P. ( 29 %) and BP America Production Company ( 10 %). If any one of Matador’s major customers were to stop purchasing its production, the Company believes there are a number of other purchasers to whom the Company could sell Matador’s production. If multiple significant customers were to discontinue purchasing Matador’s production abruptly, the Company believes it would have the resources needed to access alternative customers or markets and avoid or materially mitigate associated sales disruptions. At December 31, 2023, 2022 and 2021, approximately 38 %, 29 % and 39 %, respectively, of the Company’s accounts receivable, including joint interest billings, related to the top three purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or net realizable value and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $ 54.2 million, $ 47.8 million and $ 38.4 million of its general and administrative costs into oil and natural gas properties in 2023, 2022 and 2021, respectively. The Company capitalized $ 20.2 million, $ 10.1 million and $ 4.8 million of its interest expense into oil and natural gas properties for the years ended December 31, 2023, 2022 and 2021, respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2023, 2022 and 2021, the Company recorded depletion expense of $ 672.0 million, $ 428.9 million and $ 310.1 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10 %, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10 % discount factor is used to determine the present value of future net revenues. For the period from January through December 2023, these average oil and natural gas prices were $ 74.70 per Bbl and $ 2.64 per MMBtu, respectively. For the period from January through December 2022, these average oil and natural gas prices were $ 90.15 per Bbl and $ 6.36 per MMBtu, respectively. For the period from January through December 2021, these average oil and natural gas prices were $ 63.04 per Bbl and $ 3.60 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the years ended December 31, 2023, 2022 and 2021, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2023, 2022 and 2021. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream Properties and Other Property and Equipment +Midstream properties and other property and equipment are recorded at historical cost or acquisition date fair value and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. The Company capitalized $ 2.9 million, $ 2.2 million and $ 1.3 million of general and administrative costs into midstream properties in 2023, 2022 and 2021, respectively. The Company capitalized $ 2.1 million of interest expense into midstream properties for the year ended December 31, 2023. The Company did no t capitalize any interest expense into midstream properties for the years ended December 31, 2022 or 2021. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment. +The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. +Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of income. +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of income. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of income. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of income. See Note 12 for additional information about the Company’s derivative instruments. +Revenues +The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of income, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of income, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of income. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at Pronto’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Marlan Processing Plant”) or San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of income as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of income. +The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2023, 2022 and 2021 (in thousands). +Year Ended December 31, +2023 2022 2021 +Revenues from contracts with customers $ 2,817,621 $ 3,196,699 $ 1,862,075 +Realized loss on derivatives ( 9,575 ) ( 157,483 ) ( 220,105 ) +Unrealized (loss) gain on derivatives ( 1,261 ) 18,809 21,011 +Total revenues $ 2,806,785 $ 3,058,025 $ 1,662,981 +Year Ended December 31, +2023 2022 2021 +Oil revenues $ 2,144,894 $ 2,113,606 $ 1,205,608 +Natural gas revenues 400,705 792,132 494,934 +Third-party midstream services revenues 122,153 90,606 75,499 +Sales of purchased natural gas 149,869 200,355 86,034 +Total revenues from contracts with customers $ 2,817,621 $ 3,196,699 $ 1,862,075 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors (the “Board”) and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of income or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration, development and midstream activities. Awards that are expected to be settled in cash are liability-based awards, which are +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of income or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration, development and midstream activities. +The Company uses the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). +The Company’s consolidated statements of income for the years ended December 31, 2023, 2022 and 2021 include an equity-based compensation (non-cash) expense of $ 13.7 million, $ 15.1 million and $ 9.0 million, respectively. This equity-based compensation expense includes common stock issuances and restricted stock units expense totaling $ 1.2 million, $ 1.0 million and $ 0.9 million for the years ended December 31, 2023, 2022 and 2021, respectively, paid to independent members of the Board and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes tax benefits from an uncertain tax position on the basis of a two-step process in which (i) the +Company determines whether it is more likely than not that the tax position will be sustained upon examination by the taxing +authorities based upon the technical merits of the position and (ii) for those tax positions that meet the more-likely-than-not +recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized +upon ultimate settlement with the related tax authority. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of income. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2023, 2022 and 2021. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of midstream assets and oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2023, 2022 and 2021 (in thousands, except per share data). +Year Ended December 31, +2023 2022 2021 +Net income attributable to Matador Resources Company shareholders — numerator $ 846,074 $ 1,214,206 $ 584,968 +Weighted average common shares outstanding — denominator +Basic 119,139 118,122 116,999 +Dilutive effect of options and restricted stock units 841 2,009 2,164 +Diluted weighted average common shares outstanding 119,980 120,131 119,163 +Earnings per common share attributable to Matador Resources Company shareholders +Basic $ 7.10 $ 10.28 $ 5.00 +Diluted $ 7.05 $ 10.11 $ 4.91 +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2023 were with Bank of America, which is a lender under the Company’s reserves-based revolving credit agreement (the “Credit Agreement”). +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Segments . In November 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures , which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023 and for interim periods within fiscal years beginning after December 15, 2024. The Company is currently evaluating the impact of this standard on its disclosures. +Income Taxes . In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures , which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid. This ASU is effective for the Company prospectively to all annual periods beginning after December 15, 2024. The Company is currently evaluating the impact of this standard on its disclosures. +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2023 and 2022 (in thousands). +December 31, +2023 2022 +Oil and natural gas properties +Evaluated (subject to amortization) $ 9,633,757 $ 6,862,455 +Unproved and unevaluated (not subject to amortization) 1,193,257 977,502 +Total oil and natural gas properties 10,827,014 7,839,957 +Accumulated depletion ( 5,034,243 ) ( 4,362,292 ) +Net oil and natural gas properties 5,792,771 3,477,665 +Midstream properties +Midstream equipment and facilities 1,318,015 1,057,668 +Accumulated depreciation ( 167,116 ) ( 126,706 ) +Net midstream properties 1,150,899 930,962 +Other property and equipment +Furniture, fixtures and other equipment 17,985 13,257 +Software 8,241 8,225 +Leasehold improvements 14,149 11,365 +Total other property and equipment 40,375 32,847 +Accumulated depreciation ( 27,604 ) ( 23,277 ) +Net other property and equipment 12,771 9,570 +Net property and equipment $ 6,956,441 $ 4,418,197 +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2023 and the year in which these costs were incurred (in thousands). +Description 2023 2022 2021 2020 2019 and prior Total +Costs incurred for +Property acquisition $ 326,437 $ 97,748 $ 109,718 $ 40,355 $ 546,592 $ 1,120,850 +Exploration wells 21,359 1,298 488 303 722 24,170 +Development wells 42,904 2,198 908 542 1,685 48,237 +Total $ 390,700 $ 101,244 $ 111,114 $ 41,200 $ 548,999 $ 1,193,257 +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2023 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $ 72.4 million at December 31, 2023. Of this total, $ 24.2 million was associated with exploration wells and $ 48.2 million was associated with development wells. The +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +Company anticipates that most of the $ 72.4 million associated with these wells in progress at December 31, 2023 will be transferred to the amortization base during 2024. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2023 are costs related to the advanced preparation for wells that the Company intends to drill in the future. +NOTE 4 — LEASES +The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2023 were 5.92 % and 4.55 % for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +The following table presents supplemental consolidated statement of income information related to lease expenses, on a gross basis, for the years ended December 31, 2023 and 2022, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. +Year Ended December 31, +2023 2022 +Operating leases +Lease operating $ 25,637 $ 15,970 +Plant and other midstream services 360 285 +General and administrative 2,933 3,266 +Total operating leases (1) +28,930 19,521 +Short-term leases +Lease operating 27,252 17,437 +Plant and other midstream services 5,590 4,359 +General and administrative 63 34 +Total short-term leases (2)(3) +32,905 21,830 +Financing leases +Depreciation of assets 2,765 571 +Interest on lease liabilities 410 143 +Total financing leases 3,175 714 +Total lease expense $ 65,010 $ 42,065 +_____________________ +(1) Does not include gross payments related to drilling rig leases of $ 84.1 million and $ 58.7 million for the years ended December 31, 2023 and 2022, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2023 and 2022, respectively. +(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. +(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $ 159.7 million and $ 101.5 million for the years ended December 31, 2023 and 2022, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2023 and 2022, respectively. +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2023 and 2022, respectively (in thousands). +December 31, +2023 2022 +Operating leases +Other long-term assets $ 44,404 $ 58,798 +Other current liabilities $ ( 36,946 ) $ ( 43,921 ) +Other long-term liabilities ( 10,800 ) ( 19,532 ) +Total operating lease liabilities $ ( 47,746 ) $ ( 63,453 ) +Financing leases +Other property and equipment, at cost $ 11,316 $ 7,425 +Accumulated depreciation ( 7,236 ) ( 4,470 ) +Net property and equipment $ 4,080 $ 2,955 +Other current liabilities $ ( 1,254 ) $ ( 685 ) +Other long-term liabilities ( 869 ) ( 630 ) +Total financing lease liabilities $ ( 2,123 ) $ ( 1,315 ) +The following table presents supplemental consolidated cash flow information related to lease payments for the years ended December 31, 2023 and 2022, respectively (in thousands). +Year Ended December 31, +2023 2022 +Cash paid related to lease liabilities +Operating cash payments for operating leases $ 28,766 $ 19,290 +Investing cash payments for operating leases $ 84,065 $ 58,693 +Financing cash payments for financing leases $ 1,082 $ 620 +Right of use assets obtained in exchange for lease obligations entered into during the period +Operating leases $ 87,042 $ 80,254 +Financing leases $ 3,891 $ 1,511 +The following table presents the maturities of lease liabilities at December 31, 2023 (in years). +Weighted-Average Remaining Lease Term December 31, 2023 +Operating leases 1.4 +Financing leases 1.6 +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 4 — LEASES — Continued +The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2023 (in thousands). +December 31, 2023 +Operating Leases Financing Leases +2024 $ 36,946 $ 1,254 +2025 8,939 842 +2026 3,035 153 +2027 296 — +2028 — — +Thereafter — — +Total lease payments 49,216 2,249 +Less imputed interest ( 1,470 ) ( 126 ) +Total lease obligations 47,746 2,123 +Less current obligations ( 36,946 ) ( 1,254 ) +Long-term lease obligations $ 10,800 $ 869 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS +The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2023 and 2022 (in thousands). +Year Ended December 31, +2023 2022 +Beginning asset retirement obligations $ 53,741 $ 41,959 +Liabilities incurred during period 6,944 4,069 +Liabilities settled during period ( 1,634 ) ( 1,198 ) +Revisions in estimated cash flows 21,642 10,794 +Acquisitions during the period 8,326 — +Divestitures during the period ( 872 ) ( 4,304 ) +Accretion expense 3,943 2,421 +Ending asset retirement obligations 92,090 53,741 +Less: current asset retirement obligations (1) +( 4,605 ) ( 756 ) +Long-term asset retirement obligations $ 87,485 $ 52,985 +__________________ +(1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2023 and 2022. +F-19 +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES +Business Combinations +Advance Acquisition +On April 12, 2023, a wholly-owned subsidiary of the Company completed the acquisition of Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas (the “Initial Advance Acquisition”). The Initial Advance Acquisition had an effective date of January 1, 2023 and an aggregate purchase price consisting of (i) an amount in cash equal to approximately $ 1.60 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $ 7.5 million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $ 85 per barrel (all such payments for the 12 months in 2023, the “Contingent Consideration”). The Cash Consideration was paid upon the closing of the Initial Advance Acquisition and was funded by a combination of cash on hand and borrowings under the Credit Agreement. The Company made no payments related to the Contingent Consideration during the first, second, or third quarters of 2023. In the fourth quarter of 2023, the Company paid Contingent Consideration of $ 15.0 million, as the average oil price for the months of September and October 2023 exceeded $ 85 per barrel. +The Company recorded the Contingent Consideration at fair value on the date of the business combination and recorded the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of income. The fair value of the Contingent Consideration was $ 21.2 million at April 12, 2023. The change in fair value of the Contingent Consideration included in “Other income (expense)” during the year ended December 31, 2023 was income of $ 6.2 million. The Company used the Monte Carlo simulation method to measure the fair value of the Contingent Consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy). +On December 1, 2023, the Company acquired additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition (the “Advance Royalty Acquisition”). The Advance Royalty Acquisition had an effective date of October 1, 2023 and an aggregate purchase price of approximately $ 81.0 million (which amount is subject to certain customary post-closing adjustments), and was funded by cash on hand. +The Initial Advance Acquisition and Advance Royalty Acquisition (collectively, the “Advance Acquisition”) were accounted for under the acquisition method of accounting as a business combination in accordance with Accounting Standards Codification Topic 805, Business Combinations (“ASC Topic 805”). Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the respective acquisition dates, with any excess purchase price allocated to goodwill. The Advance Acquisition was treated as an asset acquisition for tax purposes, as the Company acquired 100 % of the membership interests of Advance in the Initial Advance Acquisition, and acquired additional overriding royalty interests and royalty interests in the Advance Royalty Acquisition. +The preliminary allocation of the total purchase price for the Advance Acquisition is set forth below (in thousands). The Company anticipates that the allocation of the purchase price should be finalized during the second quarter of 2024 upon determination of the final purchase price adjustments. +F-20 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +Consideration given +Allocation +Cash +$ 1,676,132 +Working capital adjustments ( 4,161 ) +Fair value of Contingent Consideration at April 12, 2023 21,151 +Total consideration given +$ 1,693,122 +Allocation of purchase price +Current assets $ 79,215 +Oil and natural gas properties +Evaluated +1,418,668 +Unproved and unevaluated +213,528 +Midstream assets +63,644 +Current liabilities ( 73,607 ) +Asset retirement obligations +( 8,326 ) +Net assets acquired +$ 1,693,122 +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. +Significant inputs to the valuation of oil and gas properties include estimates of: (i) future production volumes, (ii) expected operating and development costs, (iii) future commodity prices, (iv) recent market comparable transactions for unproved acreage and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change. +The results of operations for the Advance Acquisition since the respective closing dates have been included in the Company’s consolidated financial statements for the year ended December 31, 2023. The oil and natural gas production from the Advance Acquisition increased the Company’s revenues and net income for the period from April 12, 2023 through December 31, 2023 by $ 398.9 million and $ 166.9 million, respectively. +Pro Forma Information +The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the year ended December 31, 2023 and 2022, assuming the Advance Acquisition had been completed as of January 1, 2022. The pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations or the consolidated financial position of the Company would have been had the Advance Acquisition occurred on the dates noted above, nor is it necessarily indicative of the future results of operations or consolidated financial position of the Company. Future results may vary significantly from the results reflected because of various factors. +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on currently available information and certain estimates and assumptions that the Company believes provide a reasonable basis for presenting the significant effects of the Advance Acquisition, including (i) the increase in depletion reflecting the relative fair values and production volumes attributable to the acquired properties and the revision to the depletion rate reflecting the reserve volumes acquired, (ii) adjustments to interest expense as a result of the incremental borrowings necessary to finance the Advance Acquisition and (iii) the estimated tax impacts of the pro-forma adjustments. The pro forma financial information does not reflect the benefits of projected synergies, potential cost savings or the costs that may be necessary to achieve such savings, opportunities to increase revenue generation or other factors that may result from the Advance Acquisition and, accordingly, does not attempt to predict or suggest future results. Management cannot identify the timing, nature and amount of such savings, costs or other factors, any of which could affect the future consolidated results of operations or consolidated financial position of the Company. +Year Ended +December 31, +2023 2022 +Unaudited +(In thousands, except per share data) +Total revenue $ 2,969,831 $ 3,818,976 +Net income attributable to Matador Resources Company shareholders $ 937,031 $ 1,496,346 +Earnings per share: +Basic $ 7.87 $ 12.67 +Diluted $ 7.81 $ 12.46 +Pronto Acquisition +On June 30, 2022, the Company acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the acquisition (the “Pronto Acquisition”) of a wholly-owned subsidiary of Summit Midstream Partners, LP that was subsequently renamed Pronto. This acquisition was also accounted for as a business combination in accordance with ASC Topic 805. In addition, the Company assumed certain takeaway capacity on a Federal Energy Regulatory Commission regulated natural gas pipeline. As consideration for the business combination, the Company paid approximately $ 77.8 million in cash, subject to certain customary post-closing purchase price adjustments. The pro forma impact of this business combination to revenues and net income for 2022 would not be material to the Company’s 2022 revenues and net income as reported. +The allocation of the consideration given related to this business combination was as follows (in thousands), which the Company considered to be final as of December 31, 2022. +Consideration given +Allocation +Total cash consideration given +$ 77,828 +Allocation of purchase price +Cash acquired +$ 2,012 +Property, plant & equipment +74,100 +Accounts receivable +6,093 +Other assets +296 +Accrued liabilities +( 4,673 ) +Net assets acquired +$ 77,828 +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +Divestitures +During 2023 and 2022, the Company converted approximately $ 0.7 million and $ 46.5 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana. +NOTE 7 — DEBT +At December 31, 2023, the Company had (i) $ 699.2 million of outstanding 5.875 % senior notes due 2026 (the “2026 Notes”), (ii) $ 500.0 million of outstanding 6.875 % senior notes due 2028 (the “2028 Notes”), (iii) $ 500.0 million in borrowings outstanding under the Credit Agreement and (iv) approximately $ 52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. +At December 31, 2023, San Mateo had $ 522.0 million in borrowings outstanding under its revolving credit facility (the “San Mateo Credit Facility”) and approximately $ 9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. +Credit Agreements +MRC Energy Company +On November 18, 2021, the Company entered into its Fourth Amended and Restated Credit Agreement with the lenders party thereto, currently led by Truist Bank as administrative agent (the “Credit Agreement”). MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85 % of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo and Pronto are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The Credit Agreement matures on October 31, 2026 or, if earlier, the date that is 180 days prior to the earliest stated redemption date of any senior notes of the Company with an outstanding principal balance in excess of $ 25.0 million. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. +In March 2023, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the Company and its lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $ 2.25 billion, (ii) increase the elected borrowing commitment from $ 775.0 million to $ 1.25 billion, (iii) maintain the maximum facility amount at $ 1.50 billion and (iv) add another bank to the lending group. This March 2023 reaffirmation of the borrowing base constituted the regularly scheduled May 1 redetermination. +In October 2023, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the Company and its lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) increase the borrowing base from $ 2.25 billion to $ 2.50 billion, (ii) increase the elected borrowing commitment from $ 1.25 billion to $ 1.325 billion, (iii) increase the maximum facility amount from $ 1.50 billion to $ 2.00 billion and (iv) add another bank to the lending group. This October 2023 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). +In the event of an increase in the elected borrowing commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 7 — DEBT — Continued +Total deferred loan costs were $ 9.3 million at December 31, 2023, and these costs are being amortized over the term of the Credit Agreement. At December 31, 2023, the Company had $ 500.0 million in borrowings outstanding under the Credit Agreement and approximately $ 52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 7.21 % at December 31, 2023. +After giving effect to the amendment to the Credit Agreement, the applicable interest rate margin for borrowings under the Credit Agreement ranges from 1.75 % to 2.75 % for borrowings bearing interest with reference to the Adjusted Term SOFR Rate and from 0.75 % to 1.75 % for borrowings bearing interest with reference to the Alternate Base Rate (as defined in the Credit Agreement), in each case depending on the level of borrowings under the Credit Agreement. In addition, the Adjusted Term SOFR Rate includes a credit spread adjustment of 0.10 % for all interest periods. The interest period for Adjusted Term SOFR Rate borrowings may be one , three or six months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375 % to 0.50 %, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $ 75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of its assets; +• enter into commodity hedging agreements or interest rate agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and +• take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and +• a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2023. +San Mateo Midstream, LLC +On December 19, 2018, San Mateo entered into the San Mateo Credit Facility with the lenders party thereto, currently led by Truist Bank as administrative agent. In October 2023, the lenders under the San Mateo Credit Facility increased the lender +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 7 — DEBT — Continued +commitments from $ 485.0 million to $ 535.0 million and added one new bank to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in lender commitments of up to $ 735.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. +Total deferred loan costs were $ 3.1 million at December 31, 2023, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 7.71 % at December 31, 2023. At December 31, 2023, San Mateo had $ 522.0 million in borrowings outstanding under the San Mateo Credit Facility and $ 9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on December 9, 2026. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or an Adjusted Term SOFR Rate loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50 %, and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor plus 1.0 %, plus, in each case, an amount ranging from 1.25 % to 2.25 % depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as an Adjusted Term SOFR Rate loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.25 % to 3.25 % depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +A commitment fee of 0.30 % to 0.50 %, depending on San Mateo’s Consolidated Total Leverage Ratio, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur indebtedness or grant liens on any of San Mateo’s assets; +• enter into hedging agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and +• issue equity interests in San Mateo or its restricted subsidiaries. +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: +• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving San Mateo or its subsidiaries; and +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 7 — DEBT — Continued +• a change of control, as defined in the San Mateo Credit Facility. +The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2023. +Senior Unsecured Notes +2026 Notes +At December 31, 2023, the Company had $ 699.2 million of outstanding 2026 Notes, which have a 5.875 % coupon rate. The 2026 Notes were registered under the Securities Act and mature September 15, 2026. Interest is payable on the 2026 Notes semi-annually in arrears on each March 15 and September 15. The 2026 Notes are jointly and severally guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and Pronto are not Restricted Subsidiaries (as defined in the indenture governing the 2026 Notes (the “2026 Notes Indenture”)) or Guarantors of the 2026 Notes. +The Company may redeem all or a part of the 2026 Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below: +Year Redemption Price +2023 101.469 % +2024 and thereafter 100.000 % +Subject to certain exceptions, the 2026 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2026 Notes Indenture) that is a Significant Subsidiary (as defined in the 2026 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2026 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding 2026 Notes may declare all the 2026 Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• default for 30 days in the payment when due of interest on the 2026 Notes; +• default in the payment when due of the principal of, or premium, if any, on the 2026 Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase 2026 Notes pursuant to the change of control or asset sale covenants of the 2026 Notes Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the 2026 Notes Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the 2026 Notes Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 50.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 50.0 million within 60 days; +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 7 — DEBT — Continued +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +2028 Notes +On April 11, 2023, the Company completed the sale of $ 500.0 million in aggregate principal amount of the 2028 Notes, which have a 6.875 % coupon rate and mature April 15, 2028. Interest is payable on the 2028 Notes semi-annually in arrears on each April 15 and October 15. The 2028 Notes are jointly and severally guaranteed on a senior unsecured basis by the Guarantors. San Mateo and Pronto are not Restricted Subsidiaries (as defined in the indenture governing the 2028 Notes (the “2028 Notes Indenture”)) or Guarantors of the 2028 Notes. +At any time prior to April 15, 2025, the Company may redeem up to 35 % in aggregate principal amount of 2028 Notes at a redemption price of 106.875 % of the principal amount thereof, plus accrued and unpaid interest to the redemption date, in an amount not greater than the net proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65 % of the aggregate principal amount of the 2028 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2025, the Company may redeem all or part of the 2028 Notes for cash at a redemption price equal to 100 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest. +On or after April 15, 2025, the Company may redeem all or a part of the 2028 Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: +Year Redemption Price +2025 103.438 % +2026 101.719 % +2027 and thereafter 100.000 % +Subject to certain exceptions, the 2028 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including, but not limited to, the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2028 Notes Indenture) that is a Significant Subsidiary (as defined in the 2028 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2028 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding 2028 Notes may declare all the 2028 Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: +• default for 30 days in the payment when due of interest on the 2028 Notes; +• default in the payment when due of the principal of, or premium, if any, on the 2028 Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase 2028 Notes pursuant to the change of control or asset sale covenants of the 2028 Notes Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the 2028 Notes Indenture; +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 7 — DEBT — Continued +• failure by the Company for 60 days after notice to comply with any of the other agreements in the 2028 Notes Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 100.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 100.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +Debt Maturities +The components of debt, including the effects of issuance costs and net discounts, as of December 31, 2023 and 2022 are as follows (in thousands). +December 31, +2023 2022 +Revolving credit agreements: +Credit Agreement due 2026 $ 500,000 $ — +San Mateo Credit Facility due 2026 522,000 465,000 +Senior unsecured notes: +5.875 % senior notes due 2026 +699,191 699,191 +6.875 % senior notes due 2028 +500,000 — +Issuance costs and discounts, net ( 14,564 ) ( 3,946 ) +Total senior unsecured notes payable 1,184,627 695,245 +Total long-term debt $ 2,206,627 $ 1,160,245 +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 8 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2023 and 2022 is as follows (in thousands). +December 31, +2023 2022 +Deferred tax assets +Net operating loss carryforwards $ 14,387 $ 12,874 +Compensation 13,303 14,184 +Research and experimental tax credits, net of reserve 12,638 — +Lease liabilities 9,723 12,585 +Other 451 1,934 +Total deferred tax assets 50,502 41,577 +Valuation allowance on deferred tax assets ( 12,556 ) ( 11,322 ) +Total deferred tax assets, net of valuation allowance 37,946 30,255 +Deferred tax liabilities +Property and equipment ( 534,538 ) ( 378,925 ) +Less than wholly-owned subsidiaries ( 71,735 ) ( 63,388 ) +Lease right of use assets ( 9,723 ) ( 12,585 ) +Unrealized gain on derivatives ( 676 ) ( 995 ) +Other ( 2,713 ) ( 2,713 ) +Total deferred tax liabilities ( 619,385 ) ( 458,606 ) +Net deferred tax liabilities $ ( 581,439 ) $ ( 428,351 ) +The current income tax provision and the deferred income tax provision for the years ended December 31, 2023, 2022 and 2021 were comprised of the following (in thousands). +Year Ended December 31, +2023 2022 2021 +Current income tax provision +Federal income tax $ 1,554 $ 31,335 $ — +State income tax 12,368 23,542 — +Net current income tax provision $ 13,922 $ 54,877 $ — +Deferred income tax provision +Federal income tax $ 145,711 $ 302,486 $ 44,883 +State income tax 26,393 41,994 29,827 +Net deferred income tax provision $ 172,104 $ 344,480 $ 74,710 +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 8 — INCOME TAXES — Continued +Reconciliations of the tax expense computed at the statutory federal rate to the Company’s total income tax provision for the years ended December 31, 2023, 2022 and 2021 is as follows (in thousands). +Year Ended December 31, +2023 2022 2021 +Federal tax expense at statutory rate (1) +$ 230,241 $ 353,992 $ 150,223 +State income tax expense 38,525 59,870 26,646 +Permanent differences 3,558 ( 84 ) 9,612 +Non-controlling interest in subsidiaries ( 13,500 ) ( 15,143 ) ( 11,690 ) +Tax credits generated ( 109,368 ) — — +Reserve on uncertain tax positions 35,336 — — +Change in federal valuation allowance — — ( 103,262 ) +Change in state valuation allowance 1,234 722 3,181 +Total income tax provision $ 186,026 $ 399,357 $ 74,710 +__________________ +(1) The statutory federal tax rate was 21% for the years ended December 31, 2023, 2022 and 2021. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2020. The earliest tax year open for examination for the State of Texas tax return is 2019. +As of December 31, 2023, the Company had unrecognized tax benefits (“UTB”) of $ 35.3 million as a result of research and experimental expenditures related to horizontal drilling and completion innovations, which would reduce the Company’s effective tax rate in future periods if and when realized. There were no UTBs as of December 31, 2022 or 2021. Although the Company does not anticipate a material change in UTBs within the next 12 months, the timing as to when the Company will substantially resolve the uncertainties associated with the UTBs is unknown. +A reconciliation of UTBs for the years ended December 31, 2023, 2022 and 2021 is as follows (in thousands). +Year Ended December 31, +2023 2022 2021 +Balance at beginning of period $ — $ — $ — +Additions for tax positions 35,336 — — +Balance at end of period (1) +$ 35,336 $ — $ — +__________________ +(1) At December 31, 2023, the UTBs related to the U.S. federal and state of Texas jurisdictions were $ 30.7 million and $ 4.6 million, respectively. +NOTE 9 — STOCK-BASED COMPENSATION +In 2012, the Company’s Board adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. +In 2019, the Board adopted and shareholders approved the 2019 Incentive Plan. In 2022, the Board adopted and shareholders approved the first amendment to the 2019 Long-Term Incentive Plan authorizing an additional 3,725,000 shares of common stock for issuance to employees, directors, contractors or advisors of the Company. As of December 31, 2023, the 2019 Incentive Plan provided for a maximum of 4,488,901 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +The 2012 Incentive Plan and 2019 Incentive Plan (collectively, the “LTIPs”) are administered by the independent members of the Board, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. +During the years ended December 31, 2023, 2022 and 2021, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. +In 2022, the Board adopted and shareholders approved an Employee Stock Purchase Plan (the “ESPP”), which authorizes a maximum of 4.0 million shares of common stock to be purchased. The purpose of the ESPP is to encourage and enable the Company’s eligible employees to acquire an interest in the Company through the ownership of common stock. At December 31, 2023, the Company had 3,934,015 remaining shares available for issuance under the ESPP. +Service-Based Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2023, 2022 and 2021 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year period. Performance-based restricted stock units granted in 2023 and 2022 vest in an amount between zero and 200 % of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2025 and 2024, respectively, as compared to a designated peer group, and will be settled in equity. +Equity-Based +A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2023 is presented below (in thousands, except fair value). +Restricted Stock Restricted Stock Units +Service Based Service Based Performance Based +Non-vested restricted stock and +restricted stock units Shares Weighted +average +fair +value Shares Weighted +average +fair +value Shares Weighted +average +fair +value +Non-vested at December 31, 2022 +658 $ 24.59 16 $ 66.16 596 $ 56.31 +Granted 277 $ 53.53 24 $ 51.50 144 $ 87.39 +Vested (1) +( 290 ) $ 19.90 ( 16 ) $ 66.16 ( 281 ) $ 50.53 +Forfeited ( 49 ) $ 47.50 — $ — ( 103 ) $ 54.81 +Non-vested at December 31, 2023 +596 $ 47.31 24 $ 51.50 356 $ 73.82 +__________________ +(1) On December 31, 2023, 280,500 of the performance-based awards that were granted in 2021 vested. The vested units earned 178 % for each vested award representing 499,290 aggregate shares of common stock, which were issued on December 31, 2023. +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +Liability-Based +A summary of the non-vested liability-based restricted stock units as of December 31, 2023 is presented below (in thousands). +Non-vested restricted stock units Shares +Non-vested at December 31, 2022 +722 +Granted 229 +Vested ( 379 ) +Forfeited ( 107 ) +Non-vested at December 31, 2023 +465 +During the years ended December 31, 2023, 2022 and 2021, the Company settled 378,852 , 587,251 and 487,252 liability-based awards, respectively, for $ 20.5 million, $ 30.8 million and $ 12.4 million in cash, respectively. +At December 31, 2023, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ 82.8 million, of which $ 26.7 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. +At December 31, 2023, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $ 49.2 million, of which $ 17.6 million is expected to be settled in cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.7 years. +The fair value of restricted stock and restricted stock units vested during 2023, 2022 and 2021 was $ 64.8 million, $ 99.6 million and $ 51.9 million, respectively. +Summary +During the years ended December 31, 2023, 2022 and 2021, the total expense attributable to restricted stock and restricted stock units was $ 33.0 million, $ 51.6 million and $ 36.3 million, respectively. During the year ended December 31, 2023, the Company did not recognize expense attributable to stock options. During the years ended December 31, 2022 and 2021, the total expense attributable to stock options was $ 0.5 million and $ 1.0 million, respectively. During the years ended December 31, 2023, 2022 and 2021, the Company capitalized $ 7.4 million, $ 5.0 million and $ 7.2 million, respectively, related to stock-based compensation and expensed the remaining $ 25.6 million, $ 47.1 million and $ 30.0 million, respectively. +The total tax benefit recognized for all stock-based compensation was $ 7.0 million, $ 11.0 million and $ 7.9 million for the years ended December 31, 2023, 2022 and 2021, respectively. +NOTE 10 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3 % of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $ 2.2 million, $ 1.8 million and $ 1.6 million in 2023, 2022 and 2021, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $ 2.8 million, $ 2.3 million and $ 2.1 million in 2023, 2022 and 2021, respectively. The Company made no additional contributions in any reporting period presented. +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 11 — EQUITY +Common Stock Dividend +The Board declared quarterly cash dividends of $ 0.15 per share of common stock in each of the first, second and third quarters of 2023. The first quarter dividend, which totaled $ 17.8 million was paid on March 9, 2023 to shareholders of record as of February 27, 2023. The second quarter dividend, which totaled $ 17.9 million, was paid on June 1, 2023 to shareholders of record as of May 11, 2023. The third quarter dividend, which totaled $ 17.8 million, was paid on September 1, 2023 to shareholders of record as of August 11, 2023. In October 2023, the Board amended the Company’s dividend policy to increase the quarterly dividend to $ 0.20 per share of common stock and also declared a quarterly cash dividend of $ 0.20 per share of common stock. The fourth quarter dividend, which totaled $ 23.7 million, was paid on December 1, 2023 to shareholders of record as of November 10, 2023. +The Board declared a quarterly cash dividend of $ 0.05 per share of common stock in each of the first two quarters of 2022 and the Board declared a quarterly cash dividend of $ 0.10 per share of common stock for the last two quarters of 2022. Total cash dividends declared and paid totaled $ 77.2 million and $ 35.2 million, respectively, during the years ended December 31, 2023 and 2022. +On February 13, 2024, the Board declared a quarterly cash dividend of $ 0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. +Treasury Stock +On October 19, 2023, October 20, 2022 and October 21, 2021, Matador’s Board canceled all of the shares of treasury stock outstanding as of September 30, 2023, 2022 and 2021, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2023, 2022 and 2021 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +San Mateo Distributions and Contributions +During the years ended December 31, 2023, 2022 and 2021, San Mateo distributed $ 81.4 million, $ 89.5 million and $ 64.5 million, respectively, to the Company and $ 78.3 million, $ 86.0 million and $ 62.0 million, respectively, to Five Point Energy, LLC (“Five Point”), the Company’s joint venture partner in San Mateo. During the year ended December 31, 2023, the Company contributed $ 25.5 million and Five Point contributed $ 24.5 million of cash to San Mateo. During the years ended December 31, 2022 and 2021, neither the Company nor Five Point contributed cash to San Mateo. +Performance Incentives +As part of the joint venture agreements with Five Point, the Company had the potential to earn two different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $ 73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and the Wolf portion of its West Texas asset area in Loving County over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. Through January 31, 2023, the Company had earned all of the potential $ 73.5 million in performance incentives. Five Point paid $ 14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020, 2021 and 2023. Beginning in 2019, the Company had the potential to earn up to $ 150.0 million in additional deferred performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area through mid-2024, of which the Company had earned $ 85.7 million through February 20, 2024, plus additional performance incentives for securing volumes from third-party customers. During the years ended December 31, 2023 and 2022, Five Point paid $ 23.5 million and $ 28.3 million, respectively, in these additional performance incentives. Both of these performance incentives are recorded when received, net of the $ 8.0 million and $ 5.9 million deferred tax impact to Matador for the years ended December 31, 2023 and 2022, respectively, in “Additional paid-in-capital” in the Company’s consolidated balance sheets. +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of income as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2023, the Company had natural gas basis differential swap contracts open and in place to mitigate its exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. The Company had no open contracts associated with oil or NGL prices at December 31, 2023. +The following is a summary of the Company’s open basis differential swap contracts at December 31, 2023. +Notional Quantity (MMBtu) Fixed Price +($/MMBtu) Fair Value of Asset (Liability) (thousands) +Commodity Calculation Period +Natural Gas Basis Differential 01/01/2024 - 12/31/2025 21,930,000 $ ( 0.59 ) 2,670 +Total open basis differential swap contracts $ 2,670 +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2023 and December 31, 2022 (in thousands). +Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets +December 31, 2023 +Current assets $ 2,573 $ ( 461 ) $ 2,112 +Other assets 1,743 ( 1,185 ) 558 +Total $ 4,316 $ ( 1,646 ) $ 2,670 +December 31, 2022 +Current assets $ 3,930 $ — $ 3,930 +Total $ 3,930 $ — $ 3,930 +The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of income for the periods presented (in thousands). +Year Ended December 31, +Type of Instrument Location in Statements of Income 2023 2022 2021 +Derivative Instrument +Oil Revenues: Realized loss on derivatives $ — $ ( 75,806 ) $ ( 194,058 ) +Natural Gas Revenues: Realized loss on derivatives ( 9,575 ) ( 81,677 ) ( 26,047 ) +Realized loss on derivatives ( 9,575 ) ( 157,483 ) ( 220,105 ) +Oil Revenues: Unrealized gain on derivatives — 14,727 26,857 +Natural Gas Revenues: Unrealized (loss) gain on derivatives ( 1,261 ) 4,082 ( 5,846 ) +Unrealized (loss) gain on derivatives ( 1,261 ) 18,809 21,011 +Total $ ( 10,836 ) $ ( 138,674 ) $ ( 199,094 ) +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 13 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2023 and 2022 (in thousands). +Fair Value Measurements at +December 31, 2023 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Natural gas derivatives $ — $ 2,670 $ — $ 2,670 +Total $ — $ 2,670 $ — $ 2,670 +Fair Value Measurements at +December 31, 2022 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Natural gas derivatives $ — $ 3,930 $ — $ 3,930 +Total $ — $ 3,930 $ — $ 3,930 +Additional disclosures related to derivative financial instruments are provided in Note 12. +Other Fair Value Measurements +At December 31, 2023 and 2022, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities. +At December 31, 2023 and 2022, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2023 and 2022, the fair value of the 2026 Notes was $ 694.1 million and $ 675.7 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +At December 31, 2023, the fair value of the 2028 Notes was $ 510.9 million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 13 — FAIR VALUE MEASUREMENTS — Continued +the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2023 and 2022. +NOTE 14 — COMMITMENTS AND CONTINGENCIES +Processing, Transportation and Produced Water Disposal Commitments +Firm Commitments +From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $ 51.5 million and $ 48.3 million for deliveries under these agreements during the years ended December 31, 2023 and 2022, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2023, the total deficiencies required to be paid by the Company under these agreements would be approximately $ 546.0 million. +San Mateo Commitments +The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15 -year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2023 was approximately $ 218.2 million. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $ 22.2 million at December 31, 2023. +At December 31, 2023, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $ 27.9 million at December 31, 2023. The Company expects these costs to be incurred within the next year. +At December 31, 2023, the Company had outstanding midstream commitments of $ 162.7 million for the construction and installation of Pronto’s additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase 11 compressors to be utilized in San Mateo and Pronto operations. The Company expects the majority of these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 15 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2023 and 2022 (in thousands). +December 31, +2023 2022 +Accrued evaluated and unproved and unevaluated property costs $ 144,443 $ 112,766 +Accrued midstream properties costs 55,195 11,623 +Accrued lease operating expenses 62,005 46,975 +Accrued interest on debt 22,857 10,461 +Accrued asset retirement obligations 4,605 756 +Accrued partners’ share of joint interest charges 42,101 42,199 +Accrued payable related to purchased natural gas 10,400 11,158 +Other 24,242 25,372 +Total accrued liabilities $ 365,848 $ 261,310 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2023, 2022 and 2021 (in thousands). +Year Ended December 31, +2023 2022 2021 +Cash paid for income taxes, net of refunds received (1) +$ 4,597 $ 63,500 $ — +Cash paid for interest expense, net of amounts capitalized $ 111,742 $ 72,561 $ 74,843 +Increase in asset retirement obligations related to mineral properties $ 33,209 $ 9,111 $ 1,091 +Increase in asset retirement obligations related to midstream properties $ 1,197 $ 251 $ 257 +Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures $ 31,364 $ ( 13,304 ) $ 80,255 +Increase (decrease) in liabilities for acquisition of oil and natural gas properties $ 709 $ ( 2,531 ) $ 2,981 +Increase (decrease) in liabilities for midstream capital expenditures $ 43,572 $ 3,824 $ ( 4,478 ) +Stock-based compensation expense recognized as liability $ 11,380 $ 31,906 $ 24,494 +Transfer of inventory from (to) oil and natural gas properties $ 933 $ 148 $ ( 398 ) +_____________________ +(1) Represents tax payments of $ 13.5 million and $ 63.5 million for the years ended December 31, 2023 and 2022, respectively, and U.S. federal tax refunds of $ 8.9 million for the year ended December 31, 2023. +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2023 2022 2021 +Cash $ 52,662 $ 505,179 $ 48,135 +Restricted cash 53,636 42,151 38,785 +Total cash and restricted cash $ 106,298 $ 547,330 $ 86,920 +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 16 — SEGMENT INFORMATION +The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. The majority of the Company’s midstream operations in the Rustler Breaks, West Texas and Stateline asset areas and the Greater Stebbins Area in the Delaware Basin are conducted through San Mateo. In addition, at December 31, 2023, the Company operated the Marlan Processing Plant, compressor stations and natural gas gathering pipelines in Lea and Eddy Counties, New Mexico through Pronto, which is a wholly-owned subsidiary of the Company. Neither San Mateo nor Pronto is a guarantor of the 2026 Notes or the 2028 Notes. +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2023 +Oil and natural gas revenues $ 2,538,813 $ 6,786 $ — $ — $ 2,545,599 +Midstream services revenues — 346,933 — ( 224,780 ) 122,153 +Sales of purchased natural gas 23,521 126,348 — — 149,869 +Realized loss on derivatives ( 9,575 ) — — — ( 9,575 ) +Unrealized loss on derivatives ( 1,261 ) — — — ( 1,261 ) +Expenses (1) +1,417,957 304,924 99,362 ( 224,780 ) 1,597,463 +Operating income (2) +$ 1,133,541 $ 175,143 $ ( 99,362 ) $ — $ 1,209,322 +Total assets (3) +$ 6,385,762 $ 1,257,988 $ 83,246 $ — $ 7,726,996 +Capital expenditures (4) +$ 2,970,230 $ 254,393 $ 3,636 $ — $ 3,228,259 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 675.0 million and $ 40.4 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 1.3 million. +(2) Includes $ 64.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 1.81 billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ 63.6 million in midstream acquisition expenditures and $ 42.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2022 +Oil and natural gas revenues $ 2,897,336 $ 8,402 $ — $ — $ 2,905,738 +Midstream services revenues — 298,184 — ( 207,578 ) 90,606 +Sales of purchased natural gas 116,772 83,583 — — 200,355 +Realized loss on derivatives ( 157,483 ) — — — ( 157,483 ) +Unrealized gain on derivatives 18,809 — — — 18,809 +Expenses (1) +1,177,104 227,556 101,673 ( 207,578 ) 1,298,755 +Operating income (2) +$ 1,698,330 $ 162,613 $ ( 101,673 ) $ — $ 1,759,270 +Total assets (3) +$ 4,022,609 $ 1,016,580 $ 515,316 $ — $ 5,554,505 +Capital expenditures (4) +$ 903,518 $ 158,544 $ 1,213 $ — $ 1,063,275 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 429.7 million and $ 34.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.0 million. +(2) Includes $ 72.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 131.0 million attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ 75.8 million in midstream acquisition expenditures and $ 39.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2021 +Oil and natural gas revenues $ 1,695,032 $ 5,510 $ — $ — $ 1,700,542 +Midstream services revenues — 228,817 — ( 153,318 ) 75,499 +Sales of purchased natural gas 47,398 38,636 — — 86,034 +Realized loss on derivatives ( 220,105 ) — — — ( 220,105 ) +Unrealized gain on derivatives 21,011 — — — 21,011 +Expenses (1) +794,880 142,444 85,899 ( 153,318 ) 869,905 +Operating income (2) +$ 748,456 $ 130,519 $ ( 85,899 ) $ — $ 793,076 +Total assets (3) +$ 3,324,681 $ 879,672 $ 57,800 $ — $ 4,262,153 +Capital expenditures (4) +$ 778,191 $ 59,361 $ 376 $ — $ 837,928 +_____________________ +(1) Includes depletion, depreciation and amortization expenses of $ 310.9 million and $ 31.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.6 million. +(2) Includes $ 55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(3) Excludes intercompany receivables and investments in subsidiaries. +(4) Includes $ 263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $ 28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2023, 2022 and 2021 +NOTE 17 — SUBSEQUENT EVENTS +Between January 1, 2024 and February 20, 2024, a wholly-owned subsidiary of the Company acquired oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico. The consideration for the acquisitions consisted of an amount in cash equal to approximately $ 155.1 million (which amount is subject to certain customary post-closing adjustments) and the assumption of certain well costs. The Company is evaluating the accounting treatment of these transactions. +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2023, 2022 and 2021 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2023, 2022 and 2021 (in thousands). +Year Ended December 31, +2023 2022 2021 +Property acquisition costs +Proved $ 1,478,258 $ 36,985 $ 145,759 +Unproved and unevaluated 328,579 97,127 104,582 +Exploration costs 230,712 136,209 51,534 +Development costs 966,338 643,947 476,316 +Total costs incurred (1) +$ 3,003,887 $ 914,268 $ 778,191 +__________________ +(1) Excludes midstream-related development and corporate costs of approximately $258.0 million, $159.8 million and $59.7 million for the years ended December 31, 2023, 2022 and 2021, respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the year ended December 31, 2023, a majority of the Company’s property acquisition costs resulted from the Advance Acquisition. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. The Company capitalized $7.5 million of geological and geophysical costs, which are included as exploration costs in the table above, for the year ended December 31, 2021. The Company did not capitalize any geological and geophysical costs in 2023 or 2022. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were an increase of $33.8 million, an increase of $10.7 million and an increase of $1.4 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $54.2 million, $47.8 million and $38.4 million of these internal costs for the years ended December 31, 2023, 2022 and 2021, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $20.2 million, $10.1 million and $4.8 million of its interest expense for the years ended December 31, 2023, 2022 and 2021, respectively, excluding midstream-related capitalized interest expense. +Oil and Natural Gas Reserves +Proved reserves are the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2023, 2022 and 2021 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2023, 2022 and 2021 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2023, these average oil and natural gas prices were $74.70 per Bbl and $2.64 per MMBtu, respectively. For the period from January through December 2022, these average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. +F-43 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2023, 2022 and 2021 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +Net Proved Reserves +Oil Natural Gas Oil +Equivalent +(MBbl) (MMcf) (MBOE) +Total at December 31, 2020 +159,949 662,302 270,332 +Revisions of prior estimates 5,370 121,471 25,615 +Net acquisitions of minerals-in-place 7,533 11,976 9,529 +Extensions and discoveries 26,294 138,484 49,375 +Production (17,840) (81,686) (31,454) +Total at December 31, 2021 +181,306 852,547 323,397 +Revisions of prior estimates (6,953) (4,324) (7,673) +Net acquisitions (divestitures) of minerals-in-place 1,239 (1,332) 1,017 +Extensions and discoveries 42,640 215,011 78,476 +Production (21,943) (99,308) (38,495) +Total at December 31, 2022 +196,289 962,594 356,722 +Revisions of prior estimates (31,184) (88,779) (45,981) +Net acquisitions of minerals-in-place 78,550 183,311 109,102 +Extensions and discoveries 56,164 193,054 88,339 +Production (27,542) (123,420) (48,112) +Total at December 31, 2023 +272,277 1,126,760 460,070 +Proved Developed Reserves +December 31, 2020 69,647 323,160 123,507 +December 31, 2021 102,233 546,173 193,262 +December 31, 2022 116,030 632,858 221,507 +December 31, 2023 161,642 782,733 292,097 +Proved Undeveloped Reserves +December 31, 2020 90,301 339,142 146,825 +December 31, 2021 79,073 306,374 130,135 +December 31, 2022 80,259 329,736 135,215 +December 31, 2023 110,635 344,026 167,973 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2023, 2022 and 2021. +The Company’s proved oil and natural gas reserves increased 29% from 356.7 million BOE at December 31, 2022 to 460.1 million BOE at December 31, 2023. The Company’s proved oil and natural gas reserves increased by 151.5 million BOE and the Company produced 48.1 million BOE during the year ended December 31, 2023, resulting in a net increase of 103.3 million BOE. This increase in proved oil and natural gas reserves was primarily attributable to the Advance Acquisition and the Company’s delineation and development operations in the Delaware Basin during 2023. The Company increased its total proved oil and natural gas reserves by 109.1 million BOE as a result of acquisitions and trades during 2023. The Company also added 88.3 million BOE in proved reserves through extensions and discoveries during 2023, of which 27.6 million BOE resulted from new well locations drilled during 2023 to establish proved developed reserves and 60.7 million BOE resulted +F-44 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2023, 2022 and 2021 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2023. These increases were partially offset by the removal of 17.4 million BOE resulting from the 17% decrease in oil prices and the 58% decrease in natural gas prices used to estimate total proved reserves at December 31, 2023, as compared to December 31, 2022, and the removal of 31.5 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the Company’s properties in the Delaware Basin. As the Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 31.5 million BOE to proved reserves at a future date. +The Company’s proved developed oil and natural gas reserves increased 32% from 221.5 million BOE at December 31, 2022 to 292.1 million BOE at December 31, 2023. The Company’s proved developed oil and natural gas reserves increased by 118.7 million BOE and the Company produced 48.1 million BOE during the year ended December 31, 2023, resulting in a net increase of 70.6 million BOE. The Company added 27.6 million BOE in proved developed reserves through extensions and discoveries during 2023, which resulted from new well locations drilled during 2023 to establish proved reserves. In addition, during 2023 the Company converted 34.9 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin. The Company also increased its proved developed reserves by 70.2 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. Additionally, the Company realized approximately 14.1 million BOE in net downward revisions of prior estimates, most of which was attributable to the lower commodity prices used to estimate proved reserves at December 31, 2023, which resulted in shorter estimated economic lives for certain of its producing properties. +The Company’s proved undeveloped oil and natural gas reserves increased 24% from 135.2 million BOE at December 31, 2022 to 168.0 million at December 31, 2023. The Company added 60.7 million BOE in proved undeveloped reserves through extensions and discoveries during 2023, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2023. In addition, the Company increased its proved undeveloped reserves by 38.9 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. These increases were partially offset by approximately 31.9 million BOE in net downward revisions of prior estimates of proved undeveloped reserves due primarily to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking as a result of changes in development plans for certain of the properties in the Delaware Basin at December 31, 2023. +At December 31, 2023, the Company’s proved reserves were comprised of 59% oil and 41% natural gas and were approximately 63% proved developed and 37% proved undeveloped. This increase in the Company’s proved developed reserves to 63% of its total proved reserves at December 31, 2023 reflected a continued increase in the Company’s percentage of proved developed reserves, as compared to 62% and 60% proved developed reserves at December 31, 2022 and 2021, respectively. +The Company’s proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. The Company’s proved oil and natural gas reserves increased by 71.8 million BOE and the Company produced 38.5 million BOE during the year ended December 31, 2022, resulting in a net increase of 33.3 million BOE. The Company added 78.5 million BOE in proved reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations drilled during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2022. The Company realized approximately 7.7 million BOE in net downward revisions of prior estimates due primarily to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking as a result of changes in development plans for certain of the properties in the Delaware Basin at December 31, 2022. +The Company’s proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. The Company’s proved oil and natural gas reserves increased by 84.5 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021, resulting in a net increase of 53.1 million BOE. The Company added 49.4 million BOE in proved reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2021. The Company realized approximately 25.6 million BOE in net upward revisions of prior estimates, primarily driven by a 40.1 million BOE increase due to significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its properties. The Company also had small upward revisions of prior estimates attributable to increased working interests and lower estimated +F-45 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2023, 2022 and 2021 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +operating costs on certain of its properties. These upward revisions were partially offset by approximately 16.3 million BOE in downward revisions of prior estimates due primarily to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking as a result of changes in development plans for certain of the properties in the Delaware Basin at December 31, 2021. In addition, the Company realized 9.5 million BOE in net increases to its proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2023, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $74.70 per Bbl and $2.64 per MMBtu, respectively. For the period from January through December 2022, the comparable average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. For the period from January through December 2021, the comparable average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production, development and plugging and abandonment costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2023, 2022 and 2021 (in thousands). +Year Ended December 31, +2023 2022 2021 +Future cash inflows $ 23,662,653 $ 24,952,118 $ 15,174,065 +Future production costs (7,717,106) (6,752,752) (4,588,677) +Future development costs (2,162,625) (1,776,029) (1,251,581) +Future income tax expense (2,939,514) (3,935,271) (1,836,009) +Future net cash flows 10,843,408 12,488,066 7,497,798 +10% annual discount for estimated timing of cash flows (4,729,916) (5,504,863) (3,122,373) +Standardized measure of discounted future net cash flows $ 6,113,492 $ 6,983,203 $ 4,375,425 +F-46 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2023, 2022 and 2021 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2023, 2022 and 2021 (in thousands). +Year Ended December 31, +2023 2022 2021 +Balance, beginning of period $ 6,983,203 $ 4,375,425 $ 1,584,399 +Net change in sales and transfer prices and in production (lifting) costs related to future production (3,074,085) 4,046,504 3,347,910 +Changes in estimated future development costs (504,323) (744,687) (238,871) +Sales and transfers of oil and natural gas produced during the period (2,037,451) (2,466,440) (1,412,591) +Net purchases of reserves in place 2,113,620 28,841 178,695 +Net change due to extensions and discoveries 1,711,389 2,017,170 620,235 +Net change due to revisions in estimates of reserves quantities (890,794) (8,576) 786,061 +Previously estimated development costs incurred during the period 441,671 434,336 240,664 +Accretion of discount 807,896 475,474 165,799 +Other 3,913 1,982 1,737 +Net change in income taxes 558,453 (1,176,826) (898,613) +Standardized measure of discounted future net cash flows $ 6,113,492 $ 6,983,203 $ 4,375,425 +F-47 \ No newline at end of file diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/filing_metadata.csv b/raw/filings/0001520006/2023/0001520006-24-000078/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..1a4cfb35b0c8fb89faec4478f2082cd06dd1560e --- /dev/null +++ b/raw/filings/0001520006/2023/0001520006-24-000078/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2024-02-27,2023-12-31,2024-02-27T18:01:28.000Z,0001520006-24-000078,mtdr-20231231.htm,10-K,14348419,1,1,https://www.sec.gov/Archives/edgar/data/1520006/000152000624000078/mtdr-20231231.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000624000078/,2023,2023,1 diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/item1.txt b/raw/filings/0001520006/2023/0001520006-24-000078/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..ba851b53254cf901646aba46aed152af7fbbc918 --- /dev/null +++ b/raw/filings/0001520006/2023/0001520006-24-000078/item1.txt @@ -0,0 +1,617 @@ +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (iv) references to the “Initial Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, (v) references to the “Advance Royalty Acquisition” refer to the acquisition of additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition, (vi) references to the “Advance Acquisition” refer, collectively, to the Initial Advance Acquisition and the Advance Royalty Acquisition, (vii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries, (viii) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary, and (ix) references to the “Pronto Acquisition” refer to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million. +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +2 +Table of Contents +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Pronto; +• maintain our financial discipline; +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +The successful execution of our business strategies, including the Advance Acquisition, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2023. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down some of the borrowings that funded the Advance Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC (“Five Point”), our joint venture partner in San Mateo. Further, we completed several important financing transactions in 2023, including the issuance of the 2028 Notes (as defined below), increasing the elected borrowing commitment and the borrowing base under our Credit Agreement (as defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved important milestones in 2023, including the addition of produced water disposal capacity and being awarded new customer contracts. These actions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position. +2023 Highlights +Advance Acquisition +On April 12, 2023, we completed the Initial Advance Acquisition, pursuant to which our wholly-owned subsidiary acquired Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas. The Initial Advance Acquisition had an effective date of January 1, 2023 and an aggregate purchase price consisting of (i) an amount in cash equal to approximately $1.60 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $7.5 million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $85 per barrel (all such payments for the 12 months in 2023, the “Contingent Consideration”). The Cash Consideration was paid upon the closing of the Initial Advance Acquisition and was funded by a combination of cash on hand and borrowings under the Credit Agreement. We made no payments related to the Contingent Consideration during the first, second or third quarters of 2023. In the fourth quarter of 2023, we paid Contingent Consideration of $15.0 million, as the average oil price for the months of September and October 2023 exceeded $85 per barrel. +On December 1, 2023, we completed the Advance Royalty Acquisition, pursuant to which we acquired additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition. The Advance Royalty Acquisition had an effective date of October 1, 2023 with an aggregate purchase price of approximately $81.0 million (which amount is subject to certain customary post-closing adjustments) and was funded by cash on hand. +The results of operations for the Initial Advance Acquisition and the Advance Royalty Acquisition since the respective closing dates have been included in our consolidated financial statements for the year ended December 31, 2023. The oil and natural gas production from the Advance Acquisition increased our revenues and net income for the period from April 12, 2023 through December 31, 2023 by $398.9 million and $166.9 million, respectively. See Note 5 to the consolidated financial +3 +Table of Contents +statements in this Annual Report for more information regarding the Advance Acquisition. Such information is incorporated herein by reference. +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2023, we achieved record oil, natural gas and average daily oil equivalent production. In 2023, we produced 27.5 million Bbl of oil, an increase of 26%, as compared to 21.9 million Bbl of oil produced in 2022. We also produced 123.4 Bcf of natural gas, an increase of 24% from 99.3 Bcf of natural gas produced in 2022. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022. The increase in oil and natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2023 and 2022. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, an increase of 29% from 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, at December 31, 2022. The Standardized Measure of our total proved oil and natural gas reserves decreased 12% from $6.98 billion at December 31, 2022 to $6.11 billion at December 31, 2023. The PV-10 of our total proved oil and natural gas reserves decreased 16% from $9.13 billion at December 31, 2022 to $7.70 billion at December 31, 2023. The decreases in our Standardized Measure and PV-10 were primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2023, as compared to December 31, 2022, partially offset by a 29% increase in our total proved oil and natural gas reserves at December 31, 2023, as compared to December 31, 2022. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2023, estimated proved developed reserves included 161.6 million Bbl of oil and 782.7 Bcf of natural gas, and estimated proved undeveloped reserves included 110.6 million Bbl of oil and 344.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 63% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2023. Proved developed reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas reserves at December 31, 2022. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2024. +We completed and began producing oil and natural gas from 222 gross (99.6 net) horizontal wells in the Delaware Basin in 2023, including 119 gross (94.0 net) operated and 103 gross (5.6 net) non-operated wells. At December 31, 2023, our total acreage position in the Delaware Basin was approximately 265,600 gross (152,200 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving and Ward Counties, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving and Ward Counties, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 27% to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023, as compared to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022. We expect our Delaware Basin production to increase in 2024 as we continue the delineation and development of these asset areas. +During 2023, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +4 +Table of Contents +• eight Rodney Robinson wells in the first half of 2023; +• eight Stateline wells in the first half of 2023; +• 21 Ranger wells on properties acquired in the Advance Acquisition in the second half of 2023, which was the largest single batch development project in our history; +• 17 Stebbins wells in the second half of 2023; and +• 13 Wolf wells in the second half of 2023, including our first two “U-Turn” two-mile lateral wells. +In addition to achieving these five key operational milestones, other operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2023 included: +• continued drilling of longer laterals, with average completed lateral length for operated wells turned to sales in 2023 of approximately 9,800 feet; and +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2023 of $1.16 billion, which was below our estimated range for 2023 D/C/E capital expenditures of $1.18 to $1.32 billion as provided on February 21, 2023, and was in the middle of the revised estimated range of $1.10 to $1.22 billion, as provided on July 25, 2023. +Capital Resources and Financing Highlights +During 2023, we achieved several significant and important capital resources objectives, which included: +• the generation of free cash flow in all four quarters of 2023; +• the amendment of our dividend policy in the fourth quarter of 2023, pursuant to which we increased the quarterly cash dividend from $0.15 per share of common stock to $0.20 per share of common stock; and +• the receipt of $38.2 million in performance incentives directly from Five Point. +In addition, we completed several important financing transactions in 2023 that increased our operational flexibility, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the issuance of $500.0 million in aggregate principal amount of 6.875% senior notes due 2028 (the “2028 Notes”); +• the spring and fall redetermination under our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.50 billion, as compared to $2.25 billion at December 31, 2022, (ii) increase the elected borrowing commitment to $1.325 billion, as compared to $775.0 million at December 31, 2022, (iii) increase the maximum facility amount to $2.00 billion, as compared to $1.50 billion at December 31, 2022 and (iv) add two new banks to our lending group; and +• the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in October 2023 to (i) increase the lender commitments from $485.0 million to $535.0 million and (ii) add a new bank to San Mateo’s lending group. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point, and through Pronto, which is our wholly-owned subsidiary. +San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. Volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2023 and 2022. +During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. +5 +Table of Contents +At December 31, 2023, San Mateo’s midstream system included: +• Natural Gas Assets : 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); +• Oil Assets : three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included a cryogenic natural gas processing plant with a designed inlet processing capacity of 60 MMcf per day (the “Marlan Processing Plant”), three compressor stations and approximately 70 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico, spanning from the northeastern portion of the Arrowhead asset area into the Ranger asset area. Pronto has also contracted to construct an additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities to be located near the Marlan Processing Plant. +Environmental, Social and Governance (“ESG”) Initiatives +We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and highest applicable regulatory and legal standards. More recently, we have begun formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB). +Highlights from our ESG initiatives, which generally relate to our operations in 2022 except as otherwise noted, include: +• decreased direct greenhouse gas emissions intensity by 44% in 2022, as compared to 2019; +• decreased methane emissions intensity by 61% in 2022, as compared to 2019; +• decreased flaring intensity by 84% in 2022, as compared to 2019; +• increased use of non-fresh water to 99% of total water consumption in 2022; +• increased number of wells utilizing recycled produced water to 72% of total wells completed in 2022, as compared to 16% in 2019; +• transported 98% of operated produced water and 94% of operated produced oil by pipeline in 2023; and +• provided approximately 22,000 hours of employee continuing education, equating to approximately 59 hours per employee in 2023. +These sustainability metrics have been calculated using the best information available to us. The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2023 data from our ESG initiatives in the second half of 2024 in connection with the preparation of our 2023 Sustainability Report. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2023, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +6 +Table of Contents +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2023. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +265,600 152,200 1,475 756.2 4,640 1,627 452,616 63.0 126,720 +South Texas: +Eagle Ford (5) +14,400 12,100 89 72.1 114 88 3,048 100.0 1,068 +Northwest Louisiana +Haynesville 16,200 8,900 256 18.1 138 13 3,847 100.0 3,761 +Cotton Valley (6) +15,700 14,800 66 39.0 148 35 559 100.0 264 +Area Total (7) +18,500 17,300 322 57.1 286 48 4,406 100.0 4,025 +Total 298,500 181,600 1,886 885.4 5,040 1,762 460,070 63.5 131,813 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2023. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2023, approximately two-thirds of these identified drilling locations in the Delaware Basin were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 83% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2023, these engineered drilling locations included 470 gross (206 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Yeso and Avalon formations, in the Delaware Basin. At December 31, 2023, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale or in Northwest Louisiana. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2023. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2023, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2023, we also operated approximately 90% of our Eagle Ford acreage and approximately 51% of our Haynesville acreage. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin had focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology has enhanced the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations. +7 +Table of Contents +In the western part of the Permian Basin, also known as the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2023, our total acreage position in Southeast New Mexico and West Texas was approximately 265,600 gross (152,200 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving and Ward Counties, Texas. These acreage totals included approximately 62,500 gross (36,200 net) acres in our Ranger asset area in Lea County, 58,000 gross (23,300 net) acres in our Arrowhead asset area in Eddy County, 45,700 gross (26,100 net) acres in our Rustler Breaks asset area in Eddy County, 31,900 gross (21,100 net) acres in our Antelope Ridge asset area in Lea County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County, 42,900 gross (27,100 net) acres in our Twin Lakes asset area in Lea County and 21,200 gross (15,000 net) acres in our Wolf, Jackson Trust and Quito asset areas in Loving and Ward County (collectively “West Texas”) at December 31, 2023. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka, Yeso and Morrow formations. At December 31, 2023, our acreage position in the Delaware Basin was approximately 78% held by existing production. Excluding the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, and the Twin Lakes asset area, our acreage position in the Delaware Basin was approximately 96% held by existing production at December 31, 2023. +During the year ended December 31, 2023, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 222 gross (99.6 net) horizontal wells in the Delaware Basin, including 119 gross (94.0 net) operated horizontal wells and 103 gross (5.6 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2023, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow. +As a result of our ongoing drilling and completion operations in these asset areas and the Advance Acquisition, our Delaware Basin production increased significantly in 2023. Our average daily oil equivalent production from the Delaware Basin increased approximately 27% to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023, as compared to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022. +At December 31, 2023, approximately 98% of our estimated total proved oil and natural gas reserves, or 452.6 million BOE, was attributable to the Delaware Basin, including approximately 270.1 million Bbl of oil and 1.09 Tcf of natural gas, a 31% increase, as compared to 346.8 million BOE for the year ended December 31, 2022. Our Delaware Basin proved reserves at December 31, 2023 comprised approximately 99% of our proved oil reserves and 97% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 96% of our proved natural gas reserves at December 31, 2022. +At December 31, 2023, we had identified 4,640 gross (1,627 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,287 gross (1,437 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2023, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 83% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2023, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2023, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage +8 +Table of Contents +further, we anticipate that we may identify additional locations for future drilling. At December 31, 2023, these potential future drilling locations included 470 gross (206 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Yeso and Avalon, to which we have assigned proved undeveloped reserves. +We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. +Antelope Ridge Asset Area - Lea County, New Mexico +In the Antelope Ridge asset area, we turned to sales 20 gross (16.8 net) operated wells and 18 gross (0.9 net) non-operated wells during 2023. +The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to an approximately 75% NRI on most fee leases today. At the end of the first quarter of 2023, we achieved one of our five operational milestones we set for Matador in 2023 when we turned to sales eight gross (7.7 net) wells on the Rodney Robinson leasehold. These wells were the fourth group of wells drilled on the Rodney Robinson leasehold. The eight Rodney Robinson wells, which included four Second Bone Spring Carbonate, two Third Bone Spring Carbonate, and two Wolfcamp B completions, have produced in aggregate approximately 1.7 million BOE in approximately 10 months of production. +We turned to sales an additional 12 gross (9.1 net) operated wells in the Antelope Ridge asset area at various times during 2023. In total, these 12 Antelope Ridge wells, which included one First Bone Spring Sand, five Second Bone Spring Sand, two Third Bone Spring Sand, three Wolfcamp A and one Wolfcamp B completions, have produced in aggregate approximately 1.4 million BOE in an average of approximately six months of production. +Stateline Asset Area - Eddy County, New Mexico +During the second quarter of 2023, we achieved another of our five operational milestones when we turned to sales eight gross (8.0 net) wells in the Stateline asset area. These wells, which included four Wolfcamp B, two Upper Avalon and two Lower Avalon completions, have produced in aggregate approximately 1.8 million BOE in approximately six months of production. These eight wells had average completed lateral lengths of approximately 11,100 feet. +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales 40 gross (33.1 net) operated wells and 11 gross (0.7 net) non-operated wells during 2023. In the Twin Lakes asset area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2023. +In the third quarter of 2023, we achieved another of our five operational milestones when we turned to sales 21 gross (20.4 net) wells in the Ranger asset area that were acquired as part of the Advance Acquisition. Each of these wells had a lateral length of 2.25 miles, resulting in approximately 240,000 completed lateral feet, which was the largest single batch development project in Matador’s history. These wells included three Second Bone Spring Carbonate, six Second Bone Spring Sand, six Third Bone Spring Carbonate, three Third Bone Spring Sand and three Wolfcamp A completions, which averaged 24-hour initial production tests of 1,600 BOE per day with oil cuts averaging 84% and have in aggregate produced 2.4 million BOE in approximately four months of production. +We turned to sales an additional 19 gross (12.7 net) wells in the Ranger asset area at various times during 2023, which included three First Bone Spring Sand, seven Second Bone Spring Sand, one Third Bone Spring Carbonate, seven Third Bone Spring Sand and one Wolfcamp A completions. These wells have in aggregate produced 2.1 million BOE in an average of approximately six months of production. +Arrowhead Asset Area - Eddy County, New Mexico +During the fourth quarter of 2023, we achieved another of our five operational milestones when we turned to sales 17 gross (10.6 net) Stebbins wells in the Arrowhead asset area. These wells, which included eight Wolfcamp A, seven Second Bone Spring and two First Bone Spring completions, have produced in aggregate approximately 1.2 million BOE in approximately two months of production. These 17 wells had average completed lateral lengths of approximately 8,800 feet. +We also turned to sales 30 gross (1.8 net) non-operated wells in the Arrowhead asset area during 2023. +9 +Table of Contents +West Texas Asset Area - Loving and Ward Counties, Texas +During the fourth quarter of 2023, we achieved another of our five operational milestones when we turned to sales 13 gross (11.2 net) wells in the Wolf portion of the West Texas asset area. These wells, which included seven Wolfcamp B, five Wolfcamp A and one Third Bone Spring Carbonate completions, have produced in aggregate approximately 0.6 million BOE in approximately two months of production. These 13 wells had average completed lateral lengths of approximately 10,600 feet. +We also turned to sales 17 gross (0.2 net) non-operated wells in the West Texas asset area during 2023. +Rustler Breaks Asset Area - Eddy County, New Mexico +We turned to sales 21 gross (14.3 net) operated wells in the Rustler Breaks asset area at various times in the first, second and third quarters of 2023. In total, these 21 Rustler Breaks wells, which included two First Bone Spring Sand, eight Second Bone Spring Sand, six Wolfcamp A and five Wolfcamp B completions, have produced in aggregate approximately 3.9 million BOE in an average of approximately eight months of production. +We also turned to sales 23 gross (1.8 net) non-operated wells in the Rustler Breaks asset area during 2023. +South Texas — Eagle Ford Shale and Other Formations +At December 31, 2023, our properties included approximately 14,400 gross (12,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 76% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2023. +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2023, although we did participate in one gross (0.4 net) non-operated well that turned to sales in 2023. In fact, as of December 31, 2023, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 22% to 1,068 BOE per day, including 755 Bbl of oil per day and 1.9 MMcf of natural gas per day, during 2023, as compared to 1,373 BOE per day, including 971 Bbl of oil per day and 2.4 MMcf of natural gas per day, during 2022. For each of the years ended December 31, 2023 and 2022, 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2023, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.0 million BOE, was attributable to the Eagle Ford shale, including approximately 2.1 million Bbl of oil and 5.5 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and less than 1% of our proved natural gas reserves at December 31, 2023, essentially unchanged from December 31, 2022. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells that were turned to sales in 2023. +At December 31, 2023, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2023. +For the year ended December 31, 2023, approximately 3% of our average daily oil equivalent production, or 4,025 BOE per day, including five Bbl of oil per day and 24.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or 3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2023, approximately 7% of our daily natural gas production, or 24.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to these properties. At December 31, 2023, approximately 1% of our estimated total proved reserves, or 4.4 million BOE, was attributable to our properties in Northwest Louisiana. +10 +Table of Contents +Midstream Segment +Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the West Texas asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks asset area and in Loving County, Texas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. Through January 31, 2023, we had earned all of the potential $73.5 million in performance incentives. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through mid-2024 , plus additional performance incentives for securing volumes from third-party customers. Through February 20, 2024, we had received $85.7 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and the other midstream facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2023, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +At December 31, 2023, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2023, San Mateo was gathering or transporting almost all our operated natural gas +11 +Table of Contents +production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area. +In addition, at December 31, 2023, San Mateo had an NGL pipeline connection at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners LP. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In the Wolf portion of the West Texas asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the West Texas asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2023, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2023, San Mateo gathered an average of approximately 358 MMcf of natural gas per day, an increase of 25% as compared to 287 MMcf of natural gas per day gathered during the year ended December 31, 2022. In addition, during the year ended December 31, 2023, San Mateo processed approximately 381 MMcf of natural gas per day at the Black River Processing Plant, an increase of 32%, as compared to 289 MMcf of natural gas per day processed during the year ended December 31, 2022. Natural gas gathering and processing volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. +At December 31, 2023, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and (iii) approximately 70 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. During the year ended December 31, 2023, Pronto processed an average of approximately 41 MMcf of natural gas per day. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +At December 31, 2023, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the West Texas asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2023, we estimated almost all of our oil production from the Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area was transported by pipeline. +At December 31, 2023, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2023, the San Mateo Oil Pipeline Systems had throughput of approximately 43,600 Bbl of oil per day, a decrease of 10%, as compared to throughput of approximately 48,300 Bbl of oil per day during the year ended December 31, 2022. +Produced Water Gathering and Disposal Assets +During 2023, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 20, 2024, San Mateo had nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area. At February 20, 2024, San Mateo had designed disposal capacity of approximately 475,000 Bbl of produced water per day. +During the year ended December 31, 2023, San Mateo handled approximately 376,000 Bbl of produced water per day, an increase of 4%, as compared to approximately 361,000 Bbl of produced water per day handled during the year ended December 31, 2022. +12 +Table of Contents +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo or Pronto. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2023, 2022 and 2021. +Year Ended December 31, +2023 2022 2021 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 27,542 21,943 17,840 +Natural gas (Bcf) 123.4 99.3 81.7 +Total oil equivalent (MBOE) (1) +48,112 38,495 31,454 +Average daily production (BOE/d) (1) +131,813 105,465 86,176 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 77.88 $ 96.32 $ 67.58 +Oil, with realized derivatives (per Bbl) $ 77.88 $ 92.87 $ 56.70 +Natural gas, without realized derivatives (per Mcf) $ 3.25 $ 7.98 $ 6.06 +Natural gas, with realized derivatives (per Mcf) $ 3.17 $ 7.15 $ 5.74 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 5.50 $ 7.33 $ 5.69 +Lease operating $ 5.06 $ 4.08 $ 3.46 +Plant and other midstream services operating $ 2.68 $ 2.48 $ 1.95 +Depletion, depreciation and amortization $ 14.90 $ 12.11 $ 10.97 +General and administrative $ 2.29 $ 3.02 $ 3.06 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 27,264 276 — 2 27,542 +Natural gas (Bcf) 113.9 0.7 8.2 0.6 123.4 +Total oil equivalent (MBOE) (3) +46,253 390 1,373 96 48,112 +Percentage of total annual net production 96.1 % 0.8 % 2.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 74,697 755 — 5 75,457 +Natural gas (MMcf/d) 312.1 1.9 22.6 1.5 338.1 +Total oil equivalent (BOE/d) 126,720 1,068 3,761 264 131,813 +Average Sales Prices (4) +Oil (per Bbl) $ 77.90 $ 76.10 $ — $ 74.53 $ 77.88 +Natural gas (per Mcf) $ 3.32 $ 3.54 $ 2.23 $ 2.09 $ 3.25 +Total oil equivalent (per BOE) $ 54.10 $ 60.01 $ 13.39 $ 13.61 $ 52.91 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.99 $ 32.78 $ 4.59 $ 17.79 $ 6.19 +__________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +13 +Table of Contents +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 21,585 355 — 3 21,943 +Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3 +Total oil equivalent (MBOE) (3) +36,550 501 1,383 61 38,495 +Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 59,139 971 — 9 60,119 +Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1 +Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465 +Average Sales Prices (4) +Oil (per Bbl) $ 96.34 $ 95.23 $ — $ 91.53 $ 96.32 +Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98 +Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 17,279 558 — 3 17,840 +Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7 +Total oil equivalent (MBOE) (3) +29,395 776 1,217 66 31,454 +Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 47,339 1,528 — 9 48,876 +Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8 +Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176 +Average Sales Prices (4) +Oil (per Bbl) $ 67.65 $ 65.41 $ — $ 64.40 $ 67.58 +Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06 +Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023 increased 25% from our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022. This increased production was primarily attributable to the Advance Acquisition and to our delineation and development operations in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, as compared to 105,465 BOE per day for the year ended December 31, 2022. Our average daily oil production for the year ended December 31, 2023 was 75,457 Bbl of oil per day, an increase of 26% from 60,119 Bbl of oil per day for the year ended December 31, 2022. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf of natural gas per day, an increase of 24% from 272.1 MMcf of natural gas per day for the year ended December 31, 2022. +Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022 increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to 86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was 272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended December 31, 2021. +15 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2023. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 84% in all wells that we operated at December 31, 2023. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +1,300 666.8 175 89.4 1,475 756.2 +South Texas: +Eagle Ford (2) +89 72.1 — — 89 72.1 +Northwest Louisiana: +Haynesville — — 256 18.1 256 18.1 +Cotton Valley (3) +— — 66 39.0 66 39.0 +Area Total — — 322 57.1 322 57.1 +Total 1,389 738.9 497 146.5 1,886 885.4 +__________________ +(1) Includes 223 gross (89.9 net) vertical wells that were primarily acquired in multiple transactions. +(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(3) Includes the Cotton Valley formation and shallower zones. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2023, 2022 and 2021. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +16 +Table of Contents +At December 31, (1) +2023 2022 2021 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 272,277 196,289 181,306 +Natural Gas (Bcf) 1,126.8 962.6 852.5 +Total (MBOE) (3) +460,070 356,722 323,397 +Estimated proved developed reserves: +Oil (MBbl) 161,642 116,030 102,233 +Natural Gas (Bcf) 782.7 632.9 546.2 +Total (MBOE) (3) +292,097 221,507 193,262 +Percent developed 63.5 % 62.1 % 59.8 % +Estimated proved undeveloped reserves: +Oil (MBbl) 110,635 80,259 79,073 +Natural gas (Bcf) 344.0 329.7 306.4 +Total (MBOE) (3) +167,973 135,215 130,135 +Standardized Measure (4) (in millions) +$ 6,113.5 $ 6,983.2 $ 4,375.4 +PV-10 (5) (in millions) +$ 7,704.1 $ 9,132.2 $ 5,347.6 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2023 were $74.70 per Bbl for oil and $2.64 per MMBtu for natural gas, for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas and for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2023, 2022 and 2021 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2023, 2022 and 2021 were $1.59 billion, $2.15 billion and $972.2 million, respectively. +Our estimated total proved oil and natural gas reserves increased 29% from 356.7 million BOE at December 31, 2022 to 460.1 million BOE at December 31, 2023. This increase in proved oil and natural gas reserves was primarily attributable to the Advance Acquisition and our delineation and development operations in the Delaware Basin during 2023. We increased our total proved oil and natural gas reserves by 109.1 million BOE as a result of acquisitions and trades during 2023. We also added 88.3 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2023, of which 27.6 million BOE resulted from new well locations turned to sales during 2023 to establish proved developed reserves and 60.7 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2023. These increases were partially offset by the removal of 17.4 million BOE resulting from the 17% decrease in oil prices and the 58% decrease in natural gas prices used to estimate total proved reserves at December 31, 2023, as compared to December 31, 2022, and the removal of 31.5 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 31.5 million BOE to proved reserves at a future date. +Our proved oil reserves grew 39% from approximately 196.3 million Bbl at December 31, 2022 to approximately 272.3 million Bbl at December 31, 2023. Our proved natural gas reserves increased 17% from 962.6 Bcf at December 31, 2022 to 1.13 Tcf at December 31, 2023. Our proved reserves to production ratio at December 31, 2023 was 9.6, an increase of 3% from 9.3 at December 31, 2022. +17 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves decreased 12% from $6.98 billion at December 31, 2022 to $6.11 billion at December 31, 2023. The PV-10 of our total proved oil and natural gas reserves decreased 16% from $9.13 billion at December 31, 2022 to $7.70 billion at December 31, 2023. The decreases in our Standardized Measure and PV-10 are primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2023, as compared to December 31, 2022, partially offset by the 29% increase in our total proved oil and natural gas reserves at December 31, 2023, as compared to December 31, 2022. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2023 were $74.70 per Bbl and $2.64 per MMBtu, a decrease of 17% and 58%, respectively, as compared to average oil and natural gas prices of $90.15 per Bbl and $6.36 per MMBtu used to estimate proved reserves at December 31, 2022. Our total proved reserves were made up of 59% oil and 41% natural gas at December 31, 2023 and 55% oil and 45% natural gas at December 31, 2022. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2023. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2022 221,507 +Extensions and discoveries 27,615 +Net acquisitions of minerals-in-place 70,230 +Revisions of prior estimates (14,071) +Production (48,112) +Conversion of proved undeveloped to proved developed 34,928 +As of December 31, 2023 292,097 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 32% from 221.5 million BOE at December 31, 2022 to 292.1 million BOE at December 31, 2023. We added 27.6 million BOE in proved developed reserves through extensions and discoveries during 2023, which resulted from new well locations drilled during 2023 to establish proved reserves. In addition, during 2023, we converted 34.9 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. We also increased our proved developed reserves by 70.2 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. Additionally, we realized approximately 14.1 million BOE in net downward revisions of prior estimates, most of which were attributable to the lower commodity prices used to estimate proved reserves at December 31, 2023, which resulted in shorter estimated economic lives for certain of our producing properties. These cumulative net increases of 118.7 million BOE to our proved developed reserves exceeded by 2.5 times our total oil and natural gas production of 48.1 million BOE in 2023. +Our proved developed oil reserves increased 39% from 116.0 million Bbl at December 31, 2022 to 161.6 million Bbl at December 31, 2023. Our proved developed natural gas reserves increased 24% from 632.9 Bcf at December 31, 2022 to 782.7 Bcf at December 31, 2023. Proved developed reserves constituted 63% of our total proved oil and natural gas reserves at December 31, 2023, as compared to 62% at December 31, 2022. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2023. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2022 135,215 +Extensions and discoveries 60,724 +Net acquisitions of minerals-in-place 38,872 +Revisions of prior estimates (31,910) +Conversion of proved undeveloped to proved developed (34,928) +As of December 31, 2023 167,973 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +18 +Table of Contents +Our proved undeveloped oil and natural gas reserves increased 24% from 135.2 million BOE at December 31, 2022 to 168.0 million at December 31, 2023. We added 60.7 million BOE in proved undeveloped reserves through extensions and discoveries during 2023, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2023. In addition, we increased our proved undeveloped reserves by 38.9 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. These increases were partially offset by approximately 31.9 million BOE in net downward revisions of prior estimates of proved undeveloped reserves, most of which were attributable to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. During 2023, we also converted 34.9 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. +At December 31, 2023, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2023 within five years of booking these reserves. The following table sets forth, since 2020, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2020 16,256 76.1 28,944 $ 257,590 +2021 23,965 96.6 40,071 240,664 +2022 22,515 95.3 38,403 434,336 +2023 18,492 98.6 34,928 441,671 +Total 81,228 366.6 142,346 $ 1,374,261 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +19 +Table of Contents +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2023. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 270,136 1,094.9 452,616 $ 6,070.5 $ 7,649.9 +South Texas: +Eagle Ford (5) +2,135 5.5 3,048 35.9 45.3 +Northwest Louisiana +Haynesville — 23.1 3,847 10.5 13.2 +Cotton Valley (6) +6 3.3 559 (3.4) (4.3) +Area Total 6 26.4 4,406 7.1 8.9 +Total 272,277 1,126.8 460,070 $ 6,113.5 $ 7,704.1 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2023 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2023 were approximately $1.59 billion. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2023. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from +20 +Table of Contents +Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2023. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 218,900 118,900 46,700 33,300 265,600 152,200 +South Texas: +Eagle Ford 14,400 12,100 — — 14,400 12,100 +Northwest Louisiana: +Haynesville 16,200 8,900 — — 16,200 8,900 +Cotton Valley 15,700 14,800 — — 15,700 14,800 +Area Total (1) +18,500 17,300 — — 18,500 17,300 +Total 251,800 148,300 46,700 33,300 298,500 181,600 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2023 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2029 and beyond totals 2,600 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2023. +Acres Acres Acres Acres Acres +Expiring 2024 Expiring 2025 Expiring 2026 Expiring 2027 Expiring 2028 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +5,100 2,800 10,100 5,200 10,200 4,500 11,700 11,400 6,700 6,700 +Total 5,100 2,800 10,100 5,200 10,200 4,500 11,700 11,400 6,700 6,700 +__________________ +(1) Approximately 66% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2023, +21 +Table of Contents +our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2023, approximately 3% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2023, 2022 and 2021 . +Year Ended December 31, +2023 2022 2021 +Gross Net Gross Net Gross Net +Development Wells +Productive 222 84.1 138 61.4 96 40.2 +Dry — — — — — — +Exploration Wells +Productive (1) +24 16.9 20 11.0 8 8.0 +Dry — — — — — — +Total Wells +Productive (2) +246 101.0 158 72.4 104 48.2 +Dry — — — — — — +(1) All of these wells are extension wells. +(2) Includes one gross (0.5 net) vertical well in 2023 and three gross (1.6 net) vertical wells in 2022. +At December 31, 2023, we had a total of 46 gross (37.8 net) development wells and six gross (4.9 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also generally deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted NGLs based on either a negotiated percentage of the proceeds that are generated from the sale of NGLs or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include, but are not limited to: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions or conflicts in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases such as COVID-19 and its variants; the continued threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and +22 +Table of Contents +production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled or unscheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2023, 2022 and 2021, we had three significant purchasers that accounted for approximately 76%, 70% and 72%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +23 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo and Pronto compete with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, acquire properties and provide competitive midstream services will depend upon our ability to conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Environmental +Emissions Mitigation +We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines with expected sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities. +Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control and Data Acquisition (“SCADA”) equipment at a number of our larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require. +Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions. +Water Management +Using improving technologies, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations. +Land Stewardship +24 +Table of Contents +We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S. Department of Interior Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations. +During 2023, 94% of our gross operated oil production and 98% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil, natural gas and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water. This is significant because it both (i) reduces truck traffic and increases road safety and (ii) reduces emissions. +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. +Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions +25 +Table of Contents +having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states, including Texas, in August 2022. The Department of the Interior has recently resumed lease sales in several states. +In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under NEPA in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. BLM later announced that drilling permit approvals could be considered for the subject leases, provided that the process included additional time for public comments and objections. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits, is uncertain. +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the Environmental Protection Agency (the “EPA”) suggested increasing the value of the social cost of greenhouse gases from $51 per metric ton to $190 per metric ton, and in December 2023, the EPA used $190 per metric ton as the social cost of greenhouse gases in its final rule revising New Source Performance Standards (“NSPS”) and Emission Guidelines for greenhouse gas and volatile organic compound emissions in the oil and gas sector. As part of this final rulemaking, the EPA published a peer-reviewed report on the updated social cost of greenhouse gases estimates. Future EPA rulemakings may also incorporate the methodology and social cost of greenhouse gases estimate developed in this report and result in more stringent rules and regulations affecting the oil and gas sector. +In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In November 2023, the federal district court for the District of Columbia dismissed the case, holding that the environmental groups lacked standing. The environmental groups have appealed the district court’s ruling, and their appeal remains pending. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits. +In November 2022, the BLM proposed a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. The proposed rule has not yet been adopted. +26 +Table of Contents +Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Pipeline Regulation +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum +27 +Table of Contents +distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The final 2019 gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In September 2023, PHMSA issued a proposed rule applicable to gas transmission and distribution and gathering pipelines, which would require updates to emergency response plans and other safety practices. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +Underground Injection and Hydraulic Fracturing +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure +28 +Table of Contents +the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to +29 +Table of Contents +administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the EPA and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On January 18, 2023, the EPA and the Corps jointly issued a final rule revising the definition of WOTUS that largely returned to the pre-2015 regulatory regime. On September 8, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands only to those that have a continuous surface connection to water bodies. On August 29, 2023, the EPA and the Corps jointly issued a final rule, which took effect immediately, aligning the regulatory definition of WOTUS with the Supreme Court’s ruling. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration +30 +Table of Contents +and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. +In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort is designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. On December 2, 2023, the EPA issued a prepublication version of a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources. Additionally, on November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. As another example, in January 2023, the EPA announced a proposed consent decree that, if finalized as proposed, would establish a December 10, 2024 deadline for the EPA to review and propose revisions to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. +31 +Table of Contents +Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. On July 3, 2023, the USFWS issued a proposed rule to list the dunes sagebrush lizard as endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate and our ability to maximize production from our leases may be adversely impacted by these restrictions. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated +32 +Table of Contents +properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2023, we had 395 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2023, for example, our employees completed approximately 22,000 hours of continuing education and study, equating to approximately 59 hours per employee. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +33 +Table of Contents +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +34 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/item13.txt b/raw/filings/0001520006/2023/0001520006-24-000078/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2023/0001520006-24-000078/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/item9a.txt b/raw/filings/0001520006/2023/0001520006-24-000078/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ccfa52538c8736403ad13742b76edfc82d41aea1 --- /dev/null +++ b/raw/filings/0001520006/2023/0001520006-24-000078/item9a.txt @@ -0,0 +1,31 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2023, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +93 +Table of Contents +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2023 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +94 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 27, 2024 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 27, 2024 +95 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/rp_note.txt b/raw/filings/0001520006/2023/0001520006-24-000078/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2023/0001520006-24-000078/rpt_disclosure.txt b/raw/filings/0001520006/2023/0001520006-24-000078/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..2d5de659b2c6c457f1c705fa43dae2e8b663e31d --- /dev/null +++ b/raw/filings/0001520006/2023/0001520006-24-000078/rpt_disclosure.txt @@ -0,0 +1,43 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2023, there was not, nor was there proposed as of December 31, 2023, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, nominees for directors, executive officers, beneficial owners of more than 5% of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation— Compensation Discussion and Analysis” and “Director Compensation” above. +Working Interest and Overriding Royalty Interest Owners +Joseph Wm. Foran, Chairman and Chief Executive Officer, Shelley F. Appel, director, and certain of their affiliated entities (collectively, the “Foran Entities”) are working interest owners and/or overriding royalty interest owners in certain properties operated by the Company. As working interest owners, the Foran Entities are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, the Foran Entities are entitled to receive their proportionate share of revenues from the wells in which they own an interest in the normal course of business. During 2023, revenues, net of costs, received by the Foran Entities in their capacity as working interest owners or overriding royalty interest owners were approximately $19.9 million (the “Related Net Revenue Payments”). The Related Net Revenue Payments represent less than 1% of our total third-party net revenue payments during 2023. +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. During 2023, our joint interest billings to the Foran Entities attributable to their share of costs were approximately $23.3 million (the “Related Joint Interest Billings”). The Related Joint Interest Billings represent less than 1% of our total joint interest billings during 2023. As a result of this ownership by the Foran Entities, from time to time, we will be in a net receivable or net payable position with certain of the Foran Entities. We do not consider any net receivables from the Foran Entities to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Foran Entities for potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s and Ms. Appel's relationships and interests in such transactions and all other material facts related to the Related Net Revenue Payments and Related Joint Interest Billings, determined that such transactions and the Related Net Revenue Payments and Related Joint Interest Billings were fair to the Company and recommended such transactions and the Related Net Revenue Payments and Related Joint Interest Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions and the Related Net Revenue Payments and Related Joint Interest Billings. +Joint Venture Relationship +The Company has entered into a joint venture (the “Joint Venture”) with Spearpoint Resources Company (“Spearpoint”) to generate value through a well development program in our Twin Lakes asset area. An adult child of Mr. Foran and the sibling of Ms. Appel is the founder of Spearpoint and serves as the chief executive officer and chairman of the board of directors of Spearpoint. Mr. Foran’s child has a Bachelor of Arts degree in Economics from Princeton University, a Master’s of Science degree in Petroleum Engineering from Texas A&M University and a Master’s degree in Business Administration from Rice University. Mr. Foran’s child worked for a major oil and gas company as a petroleum petrophysicist. Prior to attending Texas A&M, Mr. Foran’s child served in the United States Marine Corp, including two tours of duty overseas, and has continued to serve in United State Marine Corp Reserve, recently achieving the rank of Major. Mr. Foran’s child may perform shared services to the Joint Venture, for which the Joint Venture would reimburse Spearpoint. In addition, Ms. Appel holds an ownership interest in Spearpoint. +85 Matador Resources Company | 2024 Proxy Statement +During 2023, the Company made capital contributions to the Joint Venture of approximately $3.1 million (the “Capital Contributions”) and was compensated approximately $0.9 million pursuant to the terms of the Joint Venture’s operating agreement for the provision of shared services to the Joint Venture in 2023 and Spearpoint made capital contributions to the Joint Venture of approximately $3.0 million and was compensated approximately $0.5 million in total pursuant to the terms of the Joint Venture’s operating agreement for the provision of shared services to the Joint Venture in 2021, 2022 and 2023. Neither the Company nor Spearpoint received any distributions from the Joint Venture in 2023, although such distributions may be received by the Company and/or Spearpoint in the future. +The Audit Committee reviewed the terms of the Joint Venture for potential conflicts of interest under the Related Person Transaction Policy, and, after being fully informed as to Mr. Foran’s and his adult child’s relationships and interests in such transactions and all other material facts related to the Joint Venture, determined that such transactions, including the Capital Contributions, were fair to the Company and recommended such transactions to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions, including the Capital Contributions. +Certain Employment Relationships +Billy E. Goodwin served as an executive officer during 2023 until his retirement in April of 2024. During 2023, an adult child of Mr. Goodwin was an employee of the Company and has been an employee since 2015. Mr. Goodwin’s child earned in 2023, and is expected to be compensated in 2024, between $120,000 and $500,000. Mr. Goodwin’s child has a Bachelor of Science in Business Administration degree in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General Business and Management from Oklahoma State University. He has over 13 years of industry experience, including as a drilling fluids engineer for a publicly traded oilfield services company and as a landman for a publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Goodwin’s adult child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s sister-in-law has been an employee of the Company since 2016 and earned in 2023, and is expected to be compensated in 2024, between $120,000 and $250,000. Mr. Baribault’s sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having completed the Southern Methodist University Legal Assistants Program. She has over 40 years of experience as a legal assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +An adult child of Mr. Foran and a sibling of Ms. Appel has been an employee of the Company since 2015 and earned in 2023, and is expected to be compensated in 2024, between $120,000 and $250,000. Mr. Foran’s child has a Bachelor of Science degree in Human Resource Development and a Master of Science degree in Human Resource Management, both from Texas A&M University. She has more than 12 years of industry experience, including with another publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical and anticipated compensation of Mr. Foran’s child, and all other material facts related to the relationship, determined that the employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such employment arrangement. +86 Matador Resources Company | 2024 Proxy Statement +In addition, Ms. Appel, a director and the daughter of Mr. Foran, served as the Company’s Environmental, Social and Governance Coordinator and as a Special Advisor to the Board in 2023 prior to her election to the Board in June 2023. For these services, Ms. Appel was compensated between $120,000 and $250,000. Ms. Appel has a degree from Yale University and a Master’s degree in Business Administration from the University of Chicago and also worked for a major oil and gas company for a number of years. For further details of Ms. Appel’s relationship with the Company and her background and experience, please see her biography on page 20 of this Proxy Statement. The Audit Committee reviewed the terms of the consulting arrangement for potential conflicts of interest under the Company’s Related Person Transaction Policy and, after being fully informed as to the consulting arrangement and historical and anticipated compensation of Ms. Appel, and all other material facts related to the relationship, determined that the consulting arrangement was fair to the Company and recommended the consulting arrangement to the full Board for approval and ratification. The Board subsequently approved and ratified such consulting arrangement. +Indemnification Agreements +We have entered into indemnification agreements with each of our directors and executive officers and expect to do so in the future for any new directors and executive officers. The indemnification agreements provide the directors and executive officers with contractual rights to indemnification, expense advancement and reimbursement to the fullest extent permitted by applicable law. +Procedures for Approval of Related Person Transactions +Pursuant to the Related Person Transaction Policy in effect as of December 31, 2023, a “Related Person Transaction” is defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, in which a Related Person (as defined below) has or will have a direct or indirect material interest and in which we are a participant, other than: +• a transaction involving compensation of directors that is required to be reported in our proxy statement under Item 402 of the SEC’s compensation disclosure requirements (“Item 402”); +• any employment by us of an executive officer if: +◦ the related compensation is required to be reported in our proxy statement under Item 402; or +◦ the executive officer is not an “immediate family member” of another executive officer or director of the Company, the related compensation would be reported in our proxy statement under Item 402 if the executive officer was a “named executive officer” and the Compensation Committee approved (or recommended that the Board approve) such compensation; +• a transaction with a Related Person involving less than $120,000; +• a transaction in which the interest of the Related Person arises solely from the ownership of a class of our equity securities and all holders of that class receive the same benefit on a pro rata basis; +• a transaction in which a Related Person has an indirect interest solely as a result of being (a) a director or, together with all other Related Persons, a less than 10% beneficial owner of an equity interest in another entity, or both, or (b) a limited partner in a partnership in which the Related Person, together with all other Related Persons, has an interest of less than 10%; +• a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority; +• any transaction with another company at which a Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the greater of $1,000,000, or 2% of that company’s total annual revenues; +87 Matador Resources Company | 2024 Proxy Statement +• any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount involved does not exceed the lesser of $1,000,000, or 2% of the charitable organization’s total annual receipts; +• any transaction with another publicly traded company where the Related Person’s interest arises solely from beneficial ownership of more than 5% of our Common Stock and ownership of a non-controlling interest in the other publicly traded company; +• reimbursement of business expenses incurred by a director, officer or employee of the Company in the performance of his or her duties and approved for reimbursement by the Company in accordance with the Company’s customary policies and practices; or +• indemnification and advancement of expenses made pursuant to the Certificate of Formation or the Bylaws or pursuant to any agreement. +“Related Person” means: +• any person who is, or at any time since the beginning of the Company’s last completed fiscal year was, one of our executive officers or one of our directors or nominees for director; +• any person (including any entity or group) who is known by us to be the beneficial owner of more than 5% of our Common Stock; +• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law or person residing (other than a tenant or employee) in the home of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and +• any entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. +Pursuant to the Related Person Transaction Policy, the Audit Committee must review all material facts of each Related Person Transaction and recommend either approval or disapproval of the Related Person Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Person Transaction, the Audit Committee must, after reviewing all material facts of the Related Person Transaction and the Related Person’s relationship and interest, determine whether the Related Person Transaction is fair to the Company and in, or not consistent with, the interests of the Company and its shareholders. If a Related Person Transaction will be ongoing, the Audit Committee, on at least an annual basis, will review and assess ongoing relationships with the Related Persons to see that they are in compliance with Audit Committee guidelines. Further, the policy requires that all Related Person Transactions be disclosed in our filings with the SEC and/or our website in accordance with applicable laws, rules and regulations. +88 Matador Resources Company | 2024 Proxy Statement \ No newline at end of file diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/filing.txt b/raw/filings/0001520006/2024/0001520006-25-000066/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..5231564263563b67ec64e567ada43354a8db4f56 --- /dev/null +++ b/raw/filings/0001520006/2024/0001520006-25-000066/filing.txt @@ -0,0 +1,3461 @@ +mtdr-20241231 +0001520006 false 2024 FY P5Y P1M http://fasb.org/us-gaap/2024#OtherAssetsNoncurrent http://fasb.org/us-gaap/2024#OtherAssetsNoncurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortization http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortization http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesNoncurrent P1M P3M http://www.matadorresources.com/20241231#OilBasisSwapMember http://fasb.org/us-gaap/2024#AssetsCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#AssetsCurrent http://fasb.org/us-gaap/2024#OtherAssets iso4217:USD xbrli:shares iso4217:USD xbrli:shares mtdr:purchaser xbrli:pure iso4217:USD utr:bbl iso4217:USD utr:MMBTU utr:MMcf mtdr:bank utr:bbl utr:MMBTU mtdr:segment 0001520006 2024-01-01 2024-12-31 0001520006 2024-06-30 0001520006 2025-02-18 0001520006 2024-10-01 2024-12-31 0001520006 2024-12-31 0001520006 2023-12-31 0001520006 mtdr:OilAndGasPropertiesEvaluatedMember 2024-12-31 0001520006 mtdr:OilAndGasPropertiesEvaluatedMember 2023-12-31 0001520006 mtdr:OilAndGasPropertiesUnprovedAndUnevaluatedMember 2024-12-31 0001520006 mtdr:OilAndGasPropertiesUnprovedAndUnevaluatedMember 2023-12-31 0001520006 mtdr:MidstreamPropertiesMember 2024-12-31 0001520006 mtdr:MidstreamPropertiesMember 2023-12-31 0001520006 us-gaap:PropertyPlantAndEquipmentOtherTypesMember 2024-12-31 0001520006 us-gaap:PropertyPlantAndEquipmentOtherTypesMember 2023-12-31 0001520006 us-gaap:OilAndGasMember 2024-01-01 2024-12-31 0001520006 us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2024-01-01 2024-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2023-01-01 2023-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 mtdr:NaturalGasSalesMember 2024-01-01 2024-12-31 0001520006 mtdr:NaturalGasSalesMember 2023-01-01 2023-12-31 0001520006 mtdr:NaturalGasSalesMember 2022-01-01 2022-12-31 0001520006 2023-01-01 2023-12-31 0001520006 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2021-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2021-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2021-12-31 0001520006 us-gaap:ParentMember 2021-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2021-12-31 0001520006 2021-12-31 0001520006 us-gaap:RetainedEarningsMember 2022-01-01 2022-12-31 0001520006 us-gaap:ParentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2022-01-01 2022-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2022-01-01 2022-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2022-01-01 2022-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2022-01-01 2022-12-31 0001520006 us-gaap:CommonStockMember 2022-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2022-12-31 0001520006 us-gaap:RetainedEarningsMember 2022-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2022-12-31 0001520006 us-gaap:ParentMember 2022-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2022-12-31 0001520006 2022-12-31 0001520006 us-gaap:RetainedEarningsMember 2023-01-01 2023-12-31 0001520006 us-gaap:ParentMember 2023-01-01 2023-12-31 0001520006 us-gaap:CommonStockMember 2023-01-01 2023-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2023-01-01 2023-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2023-01-01 2023-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2023-01-01 2023-12-31 0001520006 us-gaap:CommonStockMember 2023-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2023-12-31 0001520006 us-gaap:RetainedEarningsMember 2023-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2023-12-31 0001520006 us-gaap:ParentMember 2023-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2023-12-31 0001520006 us-gaap:RetainedEarningsMember 2024-01-01 2024-12-31 0001520006 us-gaap:ParentMember 2024-01-01 2024-12-31 0001520006 us-gaap:CommonStockMember 2024-01-01 2024-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2024-01-01 2024-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2024-01-01 2024-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2024-01-01 2024-12-31 0001520006 us-gaap:CommonStockMember 2024-12-31 0001520006 us-gaap:AdditionalPaidInCapitalMember 2024-12-31 0001520006 us-gaap:RetainedEarningsMember 2024-12-31 0001520006 us-gaap:TreasuryStockCommonMember 2024-12-31 0001520006 us-gaap:ParentMember 2024-12-31 0001520006 us-gaap:NoncontrollingInterestMember 2024-12-31 0001520006 mtdr:AdvanceMember 2024-01-01 2024-12-31 0001520006 mtdr:AdvanceMember 2023-01-01 2023-12-31 0001520006 mtdr:AdvanceMember 2022-01-01 2022-12-31 0001520006 mtdr:AmeredevMember 2024-01-01 2024-12-31 0001520006 mtdr:AmeredevMember 2023-01-01 2023-12-31 0001520006 mtdr:AmeredevMember 2022-01-01 2022-12-31 0001520006 mtdr:MidstreamMember 2024-01-01 2024-12-31 0001520006 mtdr:MidstreamMember 2023-01-01 2023-12-31 0001520006 mtdr:MidstreamMember 2022-01-01 2022-12-31 0001520006 srt:MinimumMember 2024-01-01 2024-12-31 0001520006 srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2024-01-01 2024-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2024-01-01 2024-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2024-01-01 2024-12-31 0001520006 mtdr:EnterpriseMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2024-01-01 2024-12-31 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 0001520006 mtdr:EnterpriseMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2023-01-01 2023-12-31 0001520006 mtdr:ThreeSignificantCustomersMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember us-gaap:RevenueFromContractWithCustomerMember 2022-01-01 2022-12-31 0001520006 mtdr:PlainsMarketingL.P.Member us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2024-01-01 2024-12-31 0001520006 mtdr:ExxonMobilCorporateMember us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2023-01-01 2023-12-31 0001520006 mtdr:BPAmericaProductionCompanyMember us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember 2022-01-01 2022-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2024-01-01 2024-12-31 0001520006 srt:MinimumMember us-gaap:MachineryAndEquipmentMember 2024-12-31 0001520006 srt:MaximumMember us-gaap:MachineryAndEquipmentMember 2024-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:MachineryAndEquipmentMember 2022-01-01 2022-12-31 0001520006 srt:OilReservesMember 2024-01-01 2024-12-31 0001520006 srt:OilReservesMember 2023-01-01 2023-12-31 0001520006 srt:OilReservesMember 2022-01-01 2022-12-31 0001520006 srt:NaturalGasReservesMember 2024-01-01 2024-12-31 0001520006 srt:NaturalGasReservesMember 2023-01-01 2023-12-31 0001520006 srt:NaturalGasReservesMember 2022-01-01 2022-12-31 0001520006 us-gaap:OilAndGasPropertiesMember 2024-12-31 0001520006 us-gaap:OilAndGasPropertiesMember 2023-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2024-12-31 0001520006 us-gaap:FurnitureAndFixturesMember 2023-12-31 0001520006 us-gaap:SoftwareDevelopmentMember 2024-12-31 0001520006 us-gaap:SoftwareDevelopmentMember 2023-12-31 0001520006 us-gaap:LeaseholdImprovementsMember 2024-12-31 0001520006 us-gaap:LeaseholdImprovementsMember 2023-12-31 0001520006 mtdr:CurrentYearMember 2024-12-31 0001520006 mtdr:PriorYearMember 2024-12-31 0001520006 mtdr:TwoYearsPriorMember 2024-12-31 0001520006 mtdr:ThreeYearsPriorMember 2024-12-31 0001520006 mtdr:ThreeYearsandPriorMember 2024-12-31 0001520006 mtdr:ProjectsInceptiontoDateMember 2024-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2024-01-01 2024-12-31 0001520006 mtdr:OperatingLeaseExpenseMember 2023-01-01 2023-12-31 0001520006 us-gaap:OilAndGasServiceMember 2024-01-01 2024-12-31 0001520006 us-gaap:OilAndGasServiceMember 2023-01-01 2023-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2024-01-01 2024-12-31 0001520006 us-gaap:GeneralAndAdministrativeExpenseMember 2023-01-01 2023-12-31 0001520006 mtdr:DrillingRigLeasesMember 2024-01-01 2024-12-31 0001520006 mtdr:DrillingRigLeasesMember 2023-01-01 2023-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2024-01-01 2024-12-31 0001520006 mtdr:DrillingRigLeasesAndOtherEquipmentRentalsMember 2023-01-01 2023-12-31 0001520006 mtdr:JointVentureMember 2024-12-18 2024-12-18 0001520006 mtdr:SanMateoMidstreamMember mtdr:MatadorResourcesCompanyMember 2024-01-01 2024-12-31 0001520006 mtdr:JointVentureMember us-gaap:CorporateJointVentureMember 2024-12-18 2024-12-18 0001520006 mtdr:JointVentureMember mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMember 2024-12-18 0001520006 mtdr:JointVentureMember mtdr:FivePointAffiliateMember mtdr:SanMateoMember 2024-12-18 0001520006 mtdr:JointVentureMember mtdr:ProntoMember 2024-12-18 0001520006 mtdr:JointVentureMember mtdr:ProntoMember 2024-01-01 2024-12-31 0001520006 mtdr:JointVentureMember mtdr:ProntoMember 2024-12-31 0001520006 mtdr:AmeredevMember mtdr:PinonMidstreamLLCMember 2024-09-18 0001520006 mtdr:AmeredevMember 2024-06-01 2024-06-01 0001520006 mtdr:AmeredevMember mtdr:AmendmentToCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2024-09-18 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember 2024-09-25 0001520006 mtdr:AmendmentToCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2024-09-25 2024-09-25 0001520006 mtdr:AmeredevMember 2024-06-01 0001520006 mtdr:AmeredevMember us-gaap:OilAndGasMember 2024-09-18 2024-12-31 0001520006 mtdr:OilAndNaturalGasProducingPropertiesAndUndevelopedAcreageInLeaCountyNewMexicoMember 2024-02-15 2024-02-15 0001520006 mtdr:OilAndNaturalGasProducingPropertiesAndUndevelopedAcreageInLeaCountyNewMexicoMember 2024-02-15 0001520006 mtdr:AdvanceMember 2023-04-12 2023-04-12 0001520006 mtdr:AdvanceMember 2023-04-12 0001520006 mtdr:AdvanceMember 2024-01-01 2024-03-31 0001520006 mtdr:AdvanceMember 2024-07-01 2024-09-30 0001520006 mtdr:AdvanceMember 2024-04-01 2024-06-30 0001520006 mtdr:AdvanceMember 2024-10-01 2024-12-31 0001520006 mtdr:AdvanceORRIAcquisitionMember 2023-10-01 2023-10-01 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-10-01 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-04-12 2023-04-12 0001520006 mtdr:InitialAdvanceAcquisitionAndAdvanceORRIAcquisitionAdvanceAcquisitionMember 2023-04-12 0001520006 us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember mtdr:PinonMidstreamLLCMember 2024-10-28 2024-10-28 0001520006 mtdr:PinonMidstreamLLCMember us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember srt:ScenarioForecastMember 2025-01-01 2025-06-30 0001520006 mtdr:CreditAgreementMember us-gaap:LetterOfCreditMember 2024-12-31 0001520006 mtdr:CreditAgreementMember us-gaap:LetterOfCreditMember 2023-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2023-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2018-08-21 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2024-12-31 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2023-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:UnsecuredDebtMember 2024-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:UnsecuredDebtMember 2023-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember 2024-04-02 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember 2024-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember 2023-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember 2024-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember 2023-12-31 0001520006 mtdr:FourthAmendedCreditAgreementMember us-gaap:LineOfCreditMember 2021-11-18 2021-11-18 0001520006 mtdr:FourthAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2024-03-22 0001520006 mtdr:AmendmentToCreditAgreementOctober2023Member us-gaap:RevolvingCreditFacilityMember 2023-10-31 0001520006 mtdr:FourthAmendedCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2024-12-03 0001520006 mtdr:CreditAgreementMember us-gaap:LetterOfCreditMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:EurodollarMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:EurodollarMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 srt:MinimumMember mtdr:BaseRateLoanMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember mtdr:BaseRateLoanMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2024-01-01 2024-12-31 0001520006 mtdr:InterestPeriodOneMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2024-01-01 2024-12-31 0001520006 mtdr:InterestPeriodTwoMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2024-01-01 2024-12-31 0001520006 mtdr:InterestPeriodThreeMember mtdr:ThirdAmendedCreditAgreementMember us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:AmendmentToCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2024-01-01 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2024-12-31 0001520006 mtdr:AmendmentToCreditAgreementMember us-gaap:RevolvingCreditFacilityMember 2024-12-31 0001520006 mtdr:ThirdAmendedCreditAgreementMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2024-11-25 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember 2024-11-26 0001520006 mtdr:SanMateoCreditFacilityMember 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember us-gaap:FederalFundsEffectiveSwapRateMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember mtdr:AdjustedLIBORateMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember mtdr:AdjustedLIBORateMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember mtdr:AdjustedLIBORateMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember mtdr:StatutoryReserveRateMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember mtdr:StatutoryReserveRateMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoCreditFacilityMember us-gaap:LineOfCreditMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:TheBankOfNovaScotiaMember mtdr:SanMateoCreditFacilityMember 2024-01-01 2024-12-31 0001520006 mtdr:TheBankOfNovaScotiaMember mtdr:SanMateoCreditFacilityMember 2024-12-31 0001520006 mtdr:A2026NotesTenderOfferMember us-gaap:UnsecuredDebtMember 2024-04-04 0001520006 mtdr:SeniorNotesDue2026Member us-gaap:UnsecuredDebtMember 2024-04-04 0001520006 mtdr:A2026NotesRedemptionMember us-gaap:UnsecuredDebtMember 2024-04-02 0001520006 mtdr:A2026NotesTenderOfferAnd2026NotesRedemptionMember us-gaap:UnsecuredDebtMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2023-04-11 2023-04-11 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember 2023-04-11 2023-04-11 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodThreeMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2028Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-04-02 2024-04-02 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember 2024-04-02 2024-04-02 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodThreeMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2032Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-09-25 2024-09-25 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember 2024-09-25 2024-09-25 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodTwoMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:SeniorNotesMember us-gaap:DebtInstrumentRedemptionPeriodThreeMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-01-01 2024-12-31 0001520006 mtdr:SeniorNotesDue2033Member us-gaap:UnsecuredDebtMember us-gaap:DebtInstrumentRedemptionPeriodOneMember 2024-12-31 0001520006 us-gaap:OtherNoncurrentLiabilitiesMember 2024-12-31 0001520006 us-gaap:OtherNoncurrentLiabilitiesMember 2023-12-31 0001520006 stpr:TX 2024-12-31 0001520006 stpr:TX 2023-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandTwelveIncentivePlanMember 2024-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2024-01-01 2024-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2024-12-31 0001520006 us-gaap:EmployeeStockMember 2023-01-01 2023-12-31 0001520006 us-gaap:EmployeeStockMember 2024-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember srt:MinimumMember 2024-01-01 2024-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember srt:MaximumMember 2024-01-01 2024-12-31 0001520006 mtdr:PerformanceBasedStockUnitsMember 2024-01-01 2024-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2024-01-01 2024-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2024-01-01 2024-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2024-01-01 2024-12-31 0001520006 mtdr:RestrictedStockServiceBasedMember 2024-12-31 0001520006 mtdr:RestrictedStockUnitsServiceBasedMember 2024-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember 2024-12-31 0001520006 mtdr:RestrictedStockUnitsPerformanceBasedMember mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember 2024-12-31 0001520006 mtdr:StockBasedCompensationTwoThousandNineteenIncentivePlanMember mtdr:RestrictedStockUnitsPerformanceBasedMember srt:MaximumMember 2024-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2023-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2024-01-01 2024-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2024-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2023-01-01 2023-12-31 0001520006 mtdr:RestrictedStockLiabilityBasedMember 2022-01-01 2022-12-31 0001520006 us-gaap:RestrictedStockMember 2024-12-31 0001520006 us-gaap:RestrictedStockMember 2024-01-01 2024-12-31 0001520006 us-gaap:RestrictedStockMember 2023-01-01 2023-12-31 0001520006 us-gaap:RestrictedStockMember 2022-01-01 2022-12-31 0001520006 2024-03-28 2024-03-28 0001520006 mtdr:O2024Q2DividendsMember 2024-01-01 2024-12-31 0001520006 mtdr:O2024Q3DividendsMember 2024-01-01 2024-12-31 0001520006 mtdr:O2024Q1DividendsMember 2024-01-01 2024-12-31 0001520006 2024-03-13 2024-03-13 0001520006 2024-06-07 2024-06-07 0001520006 2024-09-05 2024-09-05 0001520006 mtdr:O2024Q4DividendsMember 2024-01-01 2024-12-31 0001520006 2024-12-06 2024-12-06 0001520006 2023-04-01 2023-06-30 0001520006 2023-07-01 2023-09-30 0001520006 2023-01-01 2023-03-31 0001520006 2023-10-01 2023-10-31 0001520006 us-gaap:SubsequentEventMember 2025-02-18 2025-02-18 0001520006 mtdr:SanMateoMidstreamMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoMidstreamMember 2023-01-01 2023-12-31 0001520006 mtdr:SanMateoMidstreamMember 2022-01-01 2022-12-31 0001520006 mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMember 2024-01-01 2024-12-31 0001520006 mtdr:MatadorResourcesCompanyMember mtdr:SanMateoMember 2023-01-01 2023-12-31 0001520006 mtdr:FivePointMember mtdr:SanMateoMember 2024-01-01 2024-12-31 0001520006 mtdr:FivePointMember mtdr:SanMateoMember 2023-01-01 2023-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoMember 2024-12-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2017-01-01 2017-12-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2024-02-20 2024-02-20 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2019-01-01 2019-03-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2018-01-01 2018-03-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2020-01-01 2020-03-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2021-01-01 2021-03-31 0001520006 mtdr:SanMateoMidstreamMember us-gaap:CorporateJointVentureMember 2019-01-01 2019-01-01 0001520006 mtdr:SanMateoMidstreamMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2024-01-01 2024-12-31 0001520006 mtdr:JointVentureMember mtdr:FivePointMember us-gaap:CorporateJointVentureMember 2024-10-01 2024-12-31 0001520006 mtdr:FivePointMember 2024-01-01 2024-12-31 0001520006 mtdr:FivePointMember 2023-01-01 2023-12-31 0001520006 mtdr:OilCostlessCollarMember 2024-12-31 0001520006 mtdr:OilCostlessCollarMember srt:MinimumMember 2024-12-31 0001520006 mtdr:OilCostlessCollarMember srt:MaximumMember 2024-12-31 0001520006 mtdr:OilBasisSwapMember 2024-12-31 0001520006 us-gaap:OtherCurrentAssetsMember 2024-12-31 0001520006 us-gaap:OtherCurrentAssetsMember 2023-12-31 0001520006 us-gaap:OtherNoncurrentAssetsMember 2023-12-31 0001520006 mtdr:RevenuesMember srt:OilReservesMember 2024-01-01 2024-12-31 0001520006 mtdr:RevenuesMember srt:OilReservesMember 2023-01-01 2023-12-31 0001520006 mtdr:RevenuesMember srt:OilReservesMember 2022-01-01 2022-12-31 0001520006 mtdr:RevenuesMember srt:NaturalGasReservesMember 2024-01-01 2024-12-31 0001520006 mtdr:RevenuesMember srt:NaturalGasReservesMember 2023-01-01 2023-12-31 0001520006 mtdr:RevenuesMember srt:NaturalGasReservesMember 2022-01-01 2022-12-31 0001520006 mtdr:RevenuesMember 2024-01-01 2024-12-31 0001520006 mtdr:RevenuesMember 2023-01-01 2023-12-31 0001520006 mtdr:RevenuesMember 2022-01-01 2022-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember mtdr:OilDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember mtdr:OilDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember mtdr:OilDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember mtdr:OilDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2023-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2023-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2023-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember mtdr:GasDerivativesMember 2023-12-31 0001520006 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001520006 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001520006 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001520006 us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001520006 us-gaap:PipelinesMember 2023-01-01 2023-12-31 0001520006 us-gaap:PipelinesMember 2024-01-01 2024-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2024-01-01 2024-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2023-01-01 2023-12-31 0001520006 mtdr:DeliveryOfNaturalGasAndOilProductionToThirdPartiesMember 2024-12-31 0001520006 mtdr:SanMateoMidstreamMember mtdr:A201915YearFixedFeeNaturalGasTransportationAgreementMember 2024-01-01 2024-12-31 0001520006 mtdr:SanMateoMidstreamMember 2024-12-31 0001520006 mtdr:DrillingRigCommitmentsMember 2024-12-31 0001520006 us-gaap:NaturalGasMidstreamMember 2024-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2024-12-31 0001520006 mtdr:AccruedEvaluatedAndUnprovedAndUnevaluatedPropertyCostsMember 2023-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2024-12-31 0001520006 mtdr:AccruedSupportEquipmentAndFacilitiesCostsMember 2023-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2024-12-31 0001520006 mtdr:AccruedLeaseOperatingExpensesMember 2023-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2024-12-31 0001520006 mtdr:AccruedInterestOnBorrowingsUnderCreditAgreementMember 2023-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2024-12-31 0001520006 mtdr:AccruedAssetRetirementObligationsMember 2023-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2024-12-31 0001520006 mtdr:AccruedPartnersShareOfJointInterestChargesMember 2023-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2024-12-31 0001520006 mtdr:AccruedPayableRelatedToPurchasedNaturalGasMember 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:ExplorationandProductionSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2024-01-01 2024-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:NaturalGasMidstreamMember 2024-01-01 2024-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasMidstreamMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:ExplorationandProductionSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:CorporateNonSegmentMember mtdr:NaturalGasSalesMember 2024-01-01 2024-12-31 0001520006 us-gaap:IntersegmentEliminationMember mtdr:NaturalGasSalesMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2024-01-01 2024-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2024-01-01 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2024-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2024-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2024-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:NaturalGasMidstreamMember 2023-01-01 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasMidstreamMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember mtdr:NaturalGasSalesMember 2023-01-01 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember mtdr:NaturalGasSalesMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2023-01-01 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2023-01-01 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2023-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2023-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2023-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasMidstreamMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasMidstreamMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:NaturalGasSalesMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember mtdr:NaturalGasSalesMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember mtdr:NaturalGasSalesMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2022-01-01 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2022-01-01 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:ExplorationandProductionSegmentMember 2022-12-31 0001520006 us-gaap:OperatingSegmentsMember mtdr:MidstreamSegmentMember 2022-12-31 0001520006 us-gaap:CorporateNonSegmentMember 2022-12-31 0001520006 us-gaap:IntersegmentEliminationMember 2022-12-31 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31 , 2024 +or +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-35410 +Matador Resources Company +(Exact name of registrant as specified in its charter) +Texas 27-4662601 +(State or other jurisdiction of +incorporation or organization) (I.R.S. Employer +Identification No.) +5400 LBJ Freeway, Suite 1500 75240 +Dallas, Texas +(Address of principal executive offices) (Zip Code) +( 972 ) 371-5200 +(Registrant’s telephone number, including area code) +_________________________________________________________ +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Trading symbol(s) Name of each exchange on which registered +Common Stock, par value $0.01 per share MTDR New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ☒ No ☐ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. +Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ☐ No ☒ +If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements +of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ +Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ +The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $ 6,917,323,570 . +As of February 18, 2025, there were 125,207,212 shares of common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2025 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. +Auditor Name: KPMG LLP +Auditor Location: Dallas, TX +Auditor Firm ID: 185 +Table of Contents +MATADOR RESOURCES COMPANY +FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2024 +TABLE OF CONTENTS +Page +PART I +I TEM 1. +Business +2 +I TEM 1A. +Risk Factors +36 +I TEM 1B. +Unresolved Staff Comments +67 +I TEM 1C. +Cybersecurity +67 +I TEM 2. +Properties +69 +I TEM 3. +Legal Proceedings +69 +I TEM 4. +Mine Safety Disclosures +69 +PART II +I TEM 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +70 +I TEM 6. +Selected Financial Data +73 +I TEM 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +73 +I TEM 7A. +Quantitative and Qualitative Disclosures about Market Risk +91 +I TEM 8. +Financial Statements and Supplementary Data +92 +I TEM 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +92 +I TEM 9A. +Controls and Procedures +92 +I TEM 9B. +Other Information +95 +PART III +I TEM 10. +Directors, Executive Officers and Corporate Governance +95 +I TEM 11. +Executive Compensation +95 +I TEM 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +95 +I TEM 13. +Certain Relationships and Related Transactions, and Director Independence +95 +I TEM 14. +Principal Accounting Fees and Services +95 +PART IV +I TEM 15. +Exhibits and Financial Statement Schedules +96 +ITEM 16. +Form 10-K Summary +96 +i +Table of Contents +CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS +Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words. +By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and NGLs; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, capital markets, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; the operating results of and availability of any potential distributions from our joint ventures; weather and environmental conditions; disruption from our acquisitions making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions; the risk of litigation and/or regulatory actions related to our acquisitions; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: +• our business strategy; +• our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized; +• our cash flows and liquidity; +• the amount, timing and payment of dividends, if any; +• our financial strategy, budget, projections and operating results; +• the supply and demand of oil, natural gas and NGLs; +• oil, natural gas and NGL prices, including our realized prices thereof; +• the timing and amount of future production of oil and natural gas; +• the availability of drilling and production equipment; +• the availability of oil storage capacity; +• the availability of oil field labor; +• the amount, nature and timing of capital expenditures, including future exploration and development costs; +• the availability and terms of capital; +• our drilling of wells; +• our ability to negotiate and consummate acquisition and divestiture opportunities; +• the integration of acquisitions with our business; +• government regulation and taxation of the oil and natural gas industry; +• tariffs and trade restrictions; +• our marketing of oil and natural gas; +• our exploitation projects or property acquisitions; +• the ability of our midstream business to construct, maintain and operate midstream pipelines and facilities, including the operation of cryogenic natural gas processing plants and the drilling of additional salt water disposal wells; +• the ability of our midstream business to attract third-party volumes; +• our costs of exploiting and developing our properties and conducting other operations; +• general economic conditions; +• competition in the oil and natural gas industry, including in both the exploration and production and midstream segments; +• the effectiveness of our risk management and hedging activities; +• our technology; +• environmental liabilities; +1 +Table of Contents +• our initiatives and efforts relating to environmental, social and governance matters; +• counterparty credit risk; +• geopolitical instability and developments in oil-producing and natural gas-producing countries; +• our future operating results; +• the impact of the Inflation Reduction Act of 2022; and +• our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical. +Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition. +You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. +PART I +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Ameredev” refer to Ameredev Stateline II, LLC, (iv) references to “Piñon” refer to Piñon Midstream, LLC, (v) references to the “Ameredev Acquisition” refer to the acquisition of Ameredev from affiliates of EnCap Investments L.P., including (a) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (b) an approximate 19% stake in the parent company of Piñon, which was completed by a subsidiary of the Company on September 18, 2024, (vi) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (vii) references to the “Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, and the acquisition of additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico on December 1, 2023, (viii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries (including, as of December 18, 2024, Pronto), and (ix) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million. +2 +Table of Contents +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Matador; +• maintain our financial discipline; +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +The successful execution of our business strategies, including the Ameredev Acquisition, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2024. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down a portion of the borrowings that funded the Advance Acquisition and Ameredev Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC or its affiliates (“Five Point”), our joint venture partner in San Mateo. Further, we completed several important financing transactions in 2024, including the Pronto Transaction, the 2024 Equity Offering, the 2026 Notes Repurchase, the 2032 Notes Offering and the 2033 Notes Offering, twice increasing the elected borrowing commitment and the borrowing base under our Credit Agreement and increasing the lender commitments under the San Mateo Credit Facility (all as defined below). San Mateo also achieved important milestones in 2024, including completing the natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024. +2024 Highlights +Ameredev Acquisition +On September 18, 2024, our wholly-owned subsidiary completed the acquisition of Ameredev from affiliates of EnCap +Investments L.P., including (i) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (ii) an approximate 19% stake in the parent company of Piñon. The Ameredev Acquisition had an effective date of June 1, 2024 and an aggregate as-adjusted closing purchase price of approximately $1.83 billion in cash, which amount is subject to customary post-closing adjustments. The purchase price for the Ameredev Acquisition was funded by a combination of cash on hand and borrowings under our existing secured revolving credit facility (the “Credit Agreement”), which was amended on September 18, 2024 to, among other things: (i) provide for a term loan of $250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitments under the revolving credit facility from $1.50 billion to $2.25 billion. On September 25, 2024, we completed the sale of $750.0 million in aggregate principal amount of our 6.25% senior unsecured notes due 2033 (the “2033 Notes”) and used the net proceeds to partially repay borrowings outstanding under our Credit Agreement, including all of the $250.0 million in outstanding borrowings under the term loan. On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. We received $113.6 million from the sale of Piñon during the fourth quarter of 2024 and used these proceeds to reduce borrowings under our Credit Agreement. We currently expect to receive an additional $4.8 million from the sale of Piñon in the first half of 2025. +3 +Table of Contents +The results of operations for the Ameredev Acquisition since the closing date of September 18, 2024 have been included in our consolidated financial statements for the year ended December 31, 2024. The oil and natural gas production from the Ameredev Acquisition increased our revenues and net income for the period from September 18, 2024 through December 31, 2024 by $118.0 million and $34.8 million, respectively. See Note 6 to the consolidated financial statements in this Annual Report for more information regarding the Ameredev Acquisition. Such information is incorporated herein by reference. +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2024, we achieved record oil, natural gas and average daily oil equivalent production. In 2024, we produced 36.5 million Bbl of oil, an increase of 33%, as compared to 27.5 million Bbl of oil produced in 2023. We also produced 155.8 Bcf of natural gas, an increase of 26% from 123.4 Bcf of natural gas produced in 2023. Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023. The increase in oil and natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin throughout 2024, which offset declining production in the Eagle Ford shale and Northwest Louisiana. Oil production comprised 58% and 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the years ended December 31, 2024 and 2023, respectively. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, an increase of 33% from 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, at December 31, 2023. The Standardized Measure of our total proved oil and natural gas reserves increased 21% from $6.11 billion at December 31, 2023 to $7.38 billion at December 31, 2024. The PV-10 of our total proved oil and natural gas reserves increased 20% from $7.70 billion at December 31, 2023 to $9.23 billion at December 31, 2024. The increases in our Standardized Measure and PV-10 were primarily a result of a 33% increase in our total proved oil and natural gas reserves at December 31, 2024, as compared to December 31, 2023, partially offset by the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2024, as compared to December 31, 2023. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2024, estimated proved developed reserves included 206.3 million Bbl of oil and 963.2 Bcf of natural gas, and estimated proved undeveloped reserves included 155.6 million Bbl of oil and 535.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 60% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2024. Proved developed reserves and proved oil reserves comprised 63% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2023. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2025. +We completed and began producing oil and natural gas from 251 gross (110.2 net) horizontal wells in the Delaware Basin in 2024, including 124 gross (101.9 net) operated and 127 gross (8.3 net) non-operated wells. At December 31, 2024, our total acreage position in the Delaware Basin was approximately 328,000 gross (198,700 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving, Ward and Winkler Counties, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving, Ward and Winkler Counties, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 31% to 166,273 BOE per day (97% of total oil equivalent production), including 99,086 Bbl of oil per day (99% of total oil production) and 403.1 MMcf of natural gas per day (95% of total natural gas production), in 2024, as compared to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023. We expect our Delaware Basin production to increase in 2025 as we continue the delineation and development of these asset areas. +4 +Table of Contents +During 2024, we achieved several operational milestones in the Delaware Basin. These milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +• 21 Antelope Ridge wells on properties acquired in the Advance Acquisition in the first half of 2024, which matched the largest single batch development project in our history; +• Five U-Turn wells in the second half of 2024, with significantly reduced drilling time as compared to our initial U-Turn wells that we turned to sales in 2023; and +• increased efficiencies and capital savings through the introduction of Trimul-Frac and continued use of Simul-Frac. +In addition to achieving these key operational milestones, other operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2024 included: +• continued drilling of longer laterals, with average completed lateral length for operated wells turned to sales in 2024 of approximately 9,300 feet; and +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2024 of $1.32 billion, which was within our estimated range for 2024 D/C/E capital expenditures of $1.15 to $1.35 billion, as provided on October 22, 2024. +Capital Resources and Financing Highlights +During 2024, we achieved several significant and important capital resources objectives, which included: +• the generation of free cash flow in all four quarters of 2024; +• the amendment of our dividend policy in the fourth quarter of 2024, pursuant to which we increased the quarterly cash dividend from $0.20 per share of common stock to $0.25 per share of common stock; +• the receipt of $219.8 million in special distributions from San Mateo as a result of the Pronto Transaction; and +• the receipt of $23.8 million in performance incentives directly from Five Point. +In addition, we completed several financing transactions in 2024 that increased our operational flexibility, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the underwritten public offering of 5,250,000 shares of our common stock (the “2024 Equity Offering”); +• the repurchase of all of the aggregate principal amount of approximately $699.2 million of outstanding senior notes due 2026 (the “2026 Notes”) through our cash tender offer and subsequent exercise of our optional redemption right in April 2024 (the “2026 Notes Repurchase”); +• the issuance of $900.0 million in aggregate principal amount of 6.50% senior notes due 2032 (the “2032 Notes”, and such issuance, the “2032 Notes Offering”); +• the issuance of $750.0 million in aggregate principal amount of 2033 Notes (the “2033 Notes Offering”); +• the spring and fall redeterminations under, and amendments of, our Credit Agreement to collectively (i) increase the borrowing base to $3.25 billion, as compared to $2.50 billion at December 31, 2023, (ii) increase the elected borrowing commitment to $2.25 billion, as compared to $1.325 billion at December 31, 2023, (iii) increase the maximum facility amount to $3.50 billion, as compared to $2.00 billion at December 31, 2023, (iv) extend the maturity date from October 31, 2026 to March 22, 2029 and (v) add five new banks to our lending group; and +• the amendment of San Mateo’s secured revolving credit facility (the “San Mateo Credit Facility”) in November 2024 to (i) increase the lender commitments from $535.0 million to $800.0 million, (ii) extend the maturity date from December 9, 2026 to November 26, 2029 and (iii) add six new banks to San Mateo’s lending group. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point. +5 +Table of Contents +On December 18, 2024, we completed a transaction with Five Point in which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million (the “Pronto Transaction”). In connection with the Pronto Transaction, we received a special distribution from San Mateo of approximately $219.8 million. In addition, we have the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by us and 49% by Five Point. +Pronto owns and operates the Marlan cryogenic natural gas processing plant (the “Marlan Processing Plant”), which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. Pronto also owns and operates five compressor stations and approximately 120 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +In connection with the Pronto Transaction, Matador dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind Midstream Partners LLC (“Northwind”), an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing. +San Mateo achieved strong operating results in 2024, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. +In March 2024, we completed our natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024. +During 2024, San Mateo and Pronto also closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin. +At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included: +• Natural Gas Assets : 520 MMcf per day of designed natural gas cryogenic processing capacity and approximately 295 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); +• Oil Assets : three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 110 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of gas gathering, water gathering and oil transportation and gathering pipeline assets. +Environmental, Social and Governance (“ESG”) Initiatives +We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and highest applicable regulatory and legal standards. We also report on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB). +Highlights from our ESG initiatives, which generally relate to our operations in 2023 except as otherwise noted, include: +6 +Table of Contents +• decreased Exploration and Production direct greenhouse gas emissions intensity by 58% in 2023, as compared to 2019; +• decreased methane emissions intensity by 76% in 2023, as compared to 2019; +• decreased flaring intensity by 82% in 2023, as compared to 2019; +• utilized non-fresh water in 97% of total water consumption in 2023; +• increased number of wells utilizing recycled produced water to 89% of total wells completed in 2023, as compared to 72% in 2022; +• transported 99% of operated produced water and 96% of operated produced oil by pipeline in 2024; and +• provided approximately 22,500 hours of employee continuing education, equating to approximately 50 hours per employee in 2024. +The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2024 data from our ESG initiatives in the second half of 2025 in connection with the preparation of our 2024 Sustainability Report. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2024, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2024. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +328,000 198,700 1,949 1,019.8 5,080 1,869 606,196 59.7 166,273 +South Texas: +Eagle Ford (5) +2,900 2,900 31 30.3 6 4 1,667 58.8 986 +Northwest Louisiana +Haynesville 16,200 8,900 268 18.5 131 13 3,286 100.0 2,859 +Cotton Valley (6) +15,700 14,800 66 39.0 144 37 387 100.0 633 +Area Total (7) +18,500 17,300 334 57.5 275 50 3,673 100.0 3,492 +Total 349,400 218,900 2,314 1,107.6 5,361 1,923 611,536 60.0 170,751 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2024. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2024, approximately 77% of these identified drilling locations in the Delaware Basin were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 89% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2024, these engineered drilling locations included 439 gross (258 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon formations, in the Delaware Basin. At December 31, 2024, we had assigned no proved undeveloped reserves to our leasehold in Northwest Louisiana. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Yeso and Avalon plays on our acreage in the Delaware Basin at December 31, 2024. +7 +Table of Contents +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2024, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2024, we also operated approximately 100% of our Eagle Ford acreage and approximately 51% of our Northwest Louisiana acreage. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin had focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology has enhanced the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations. +In the western part of the Permian Basin, also known as the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2024, our total acreage position in Southeast New Mexico and West Texas was approximately 328,000 gross (198,700 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving, Ward and Winkler Counties, Texas. These acreage totals included approximately 73,700 gross (42,100 net) acres in our Ranger asset area in Lea County, 59,600 gross (24,000 net) acres in our Arrowhead asset area in Eddy County, 47,000 gross (26,500 net) acres in our Rustler Breaks asset area in Eddy County, 63,800 gross (50,400 net) acres in our Antelope Ridge asset area in Lea County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County, 47,300 gross (30,000 net) acres in our Twin Lakes asset area in Lea County and 33,200 gross (22,300 net) acres in our West Texas asset area in Loving, Ward and Winkler Counties at December 31, 2024. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka, Yeso and Morrow formations. At December 31, 2024, our acreage position in the Delaware Basin was approximately 79% held by existing production. Excluding the Twin Lakes asset area, our acreage position in the Delaware Basin was approximately 88% held by existing production at December 31, 2024. +During the year ended December 31, 2024, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 251 gross (110.2 net) horizontal wells in the Delaware Basin, including 124 gross (101.9 net) operated horizontal wells and 127 gross (8.3 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2024, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow. +As a result of our ongoing drilling and completion operations in these asset areas and the Ameredev Acquisition, our Delaware Basin production increased significantly in 2024. Our average daily oil equivalent production from the Delaware Basin increased approximately 31% to 166,273 BOE per day (97% of total oil equivalent production), including 99,086 Bbl of oil per day (99% of total oil production) and 403.1 MMcf of natural gas per day (95% of total natural gas production), in 2024, +8 +Table of Contents +as compared to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023. +At December 31, 2024, approximately 99% of our estimated total proved oil and natural gas reserves, or 606.2 million BOE, was attributable to the Delaware Basin, including approximately 360.4 million Bbl of oil and 1.47 Tcf of natural gas, a 34% increase, as compared to 452.6 million BOE for the year ended December 31, 2023. Our Delaware Basin proved reserves at December 31, 2024 comprised approximately 100% of our proved oil reserves and 98% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 97% of our proved natural gas reserves at December 31, 2023. +At December 31, 2024, we had identified 5,080 gross (1,869 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon, Yeso and Avalon formations. At December 31, 2024, these locations had a total net lateral length of approximately 18.3 million feet, or 3,680 miles, an increase of 22% as compared to the total net lateral length of approximately 15.0 million feet, or 2,975 miles, as of December 31, 2023. These locations include 2,546 gross (1,667 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2024, approximately 77% of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 89% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2024, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2024, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2024, these potential future drilling locations included 439 gross (258 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon and Avalon, to which we have assigned proved undeveloped reserves. +We began 2024 o perating seven drilling rigs in the Delaware Basin. We added an eighth operated drilling rig in the first quarter of 2024 and a ninth operated drilling rig late in the second quarter of 2024. Upon the consummation of the Ameredev Acquisition, we continued operating a total of nine drilling rigs for the combined Matador and Ameredev properties. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. +Antelope Ridge Asset Area - Lea County, New Mexico +In the Antelope Ridge asset area, we turned to sales 60 gross (52.2 net) operated wells and 14 gross (0.9 net) non-operated wells during 2024. +In the second quarter of 2024, we achieved an operational milestone when we turned to sales 21 gross (18.9 net) wells in the Antelope Ridge asset area that were acquired as part of the Advance Acquisition. Each of these wells had a lateral length of 1.5 miles, resulting in approximately 155,000 completed lateral feet. These wells included three First Bone Spring, six Second Bone Spring, three Third Bone Spring, six Third Bone Spring Carbonate, and three Wolfcamp A-XY completions, which averaged 24-hour initial production tests of 1,728 BOE per day with oil cuts averaging 83% and have in aggregate produced 4.2 million BOE in approximately eight months of production. +We turned to sales an additional 39 gross (33.3 net) operated wells in the Antelope Ridge asset area at various times during 2024. In total, these 39 Antelope Ridge wells, which included eight First Bone Spring, 12 Second Bone Spring, seven Third Bone Spring, four Third Bone Spring Carbonate, three Wolfcamp A-XY, two Wolfcamp A, two Wolfcamp B and one Wolfcamp D completions, have produced in aggregate approximately 2.4 million BOE in an average of approximately three months of production. These 39 wells had average completed lateral lengths of approximately 9,500 feet. +Stateline Asset Area - Eddy County, New Mexico +We turned to sales six gross (6.0 net) operated wells in the Stateline asset area during 2024. These wells, which included four Upper Avalon and two Lower Avalon completions, have produced in aggregate approximately 0.4 million BOE in approximately seven months of production. These six wells had average completed lateral lengths of approximately 12,100 feet. +We also turned to sales 18 gross (0.4 net) non-operated wells in the Stateline asset area during 2024. +9 +Table of Contents +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales ten gross (7.9 net) operated wells and 14 gross (1.9 net) non-operated wells during 2024. In the Twin Lakes asset area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2024. +In total, these ten Ranger operated wells, which included four First Bone Spring, four Second Bone Spring, one Third Bone Spring and one Avalon completions, have produced in aggregate approximately 1.5 million BOE in an average of approximately eight months of production. These ten wells had average completed lateral lengths of approximately 10,100 feet. +Arrowhead Asset Area - Eddy County, New Mexico +We turned to sales 16 gross (12.3 net) operated wells in the Arrowhead asset area during 2024. These wells, which included eight Wolfcamp A and eight Second Bone Spring completions, have produced in aggregate approximately 2.5 million BOE in approximately six months of production. These 16 wells had average completed lateral lengths of approximately 9,800 feet. +We also turned to sales 23 gross (1.7 net) non-operated wells in the Arrowhead asset area during 2024. +Rustler Breaks Asset Area - Eddy County, New Mexico +We turned to sales 32 gross (23.5 net) operated wells in the Rustler Breaks asset area during 2024. In total, these 32 Rustler Breaks wells, which included ten First Bone Spring, six Second Bone Spring, 12 Third Bone Spring Carbonate and four Wolfcamp B completions, have produced in aggregate approximately 5.7 million BOE in an average of approximately six months of production. These 32 wells had average completed lateral lengths of approximately 9,100 feet. +We also turned to sales 48 gross (3.2 net) non-operated wells in the Rustler Breaks asset area during 2024. +West Texas Asset Area - Loving, Ward and Winkler Counties, Texas +We turned to sales ten gross (0.2 net) non-operated wells in the West Texas asset area during 2024. +South Texas — Eagle Ford Shale and Other Formations +During the fourth quarter of 2024, we divested certain non-core assets in the Eagle Ford shale for approximately $11.5 million. At December 31, 2024, our remaining properties included approximately 2,900 gross (2,900 net) acres in the Eagle Ford shale play in South Texas. All of our Eagle Ford leasehold was held by existing production at December 31, 2024. +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2024. In fact, as of December 31, 2024, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 8% to 986 BOE per day, including 719 Bbl of oil per day and 1.6 MMcf of natural gas per day, during 2024, as compared to 1,068 BOE per day, including 755 Bbl of oil per day and 1.9 MMcf of natural gas per day, during 2023. For each of the years ended December 31, 2024 and 2023, less than 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2024, less than 1% of our estimated total proved oil and natural gas reserves, or 1.7 million BOE, was attributable to the Eagle Ford shale, including approximately 1.4 million Bbl of oil and 1.4 Bcf of natural gas. Our Eagle Ford total proved reserves comprised less than 1% of our proved oil reserves and less than 1% of our proved natural gas reserves at December 31, 2024, essentially unchanged from December 31, 2023. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that were turned to sales in 2024. +At December 31, 2024, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024. +For the year ended December 31, 2024, approximately 2% of our average daily oil equivalent production, or 3,492 BOE per day, including three Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2023, approximately 3% of our average daily oil equivalent production, or 4,025 BOE per day, including five Bbl of oil per day and 24.1 MMcf of natural gas per day, was attributable to +10 +Table of Contents +our properties in Northwest Louisiana. For the year ended December 31, 2024, approximately 5% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2023, approximately 7% of our daily natural gas production, or 24.1 MMcf of natural gas per day, was attributable to these properties. At December 31, 2024, less than 1% of our estimated total proved reserves, or 3.7 million BOE, was attributable to our properties in Northwest Louisiana. +Midstream Segment +Our midstream segment conducts midstream operations in support of, and provides flow assurance for, our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the West Texas asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks asset area and in Loving County, Texas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and earned all of the potential $73.5 million in performance incentives through January 31, 2023. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we earned $108.2 million in performance incentives through September 30, 2024. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and the other midstream facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +On June 30, 2022, we acquired Pronto, including the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of gas gathering, water gathering and oil transportation and gathering pipeline assets. +On December 18, 2024, we completed the Pronto Transaction, pursuant to which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million. In connection with the Pronto Transaction, we received a special distribution from San Mateo of approximately $219.8 million. In addition, we have the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by us and 49% by Five Point. +Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. Pronto also owns and operates five compressor stations and approximately 120 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +In connection with the Pronto Transaction, Matador dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and +11 +Table of Contents +processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind, an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2024, was also gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +At December 31, 2024, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2024, San Mateo was gathering or transporting almost all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area. +In addition, at December 31, 2024, San Mateo had NGL pipeline connections at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners L.P. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In the Wolf portion of the West Texas asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the West Texas asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2024, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2024, San Mateo gathered an average of approximately 426 MMcf of natural gas per day, an increase of 19% as compared to 358 MMcf of natural gas per day gathered during the year ended December 31, 2023. In addition, during the year ended December 31, 2024, San Mateo processed approximately 403 MMcf of natural gas per day at the Black River Processing Plant, an increase of 6%, as compared to 381 MMcf of natural gas per day processed during the year ended December 31, 2023. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +At December 31, 2024, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the West Texas asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2024, we estimated almost all of our oil production from the Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area was transported by pipeline. +12 +Table of Contents +At December 31, 2024, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2024, the San Mateo Oil Pipeline Systems had throughput of approximately 52,600 Bbl of oil per day, an increase of 21%, as compared to throughput of approximately 43,600 Bbl of oil per day during the year ended December 31, 2023. +Produced Water Gathering and Disposal Assets +At December 31, 2024, San Mateo had four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area. At December 31, 2024, San Mateo had designed disposal capacity of approximately 475,000 Bbl of produced water per day. +During the year ended December 31, 2024, San Mateo handled approximately 462,400 Bbl of produced water per day, an increase of 23%, as compared to approximately 376,000 Bbl of produced water per day handled during the year ended December 31, 2023. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo as of December 31, 2024. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2024, 2023 and 2022. +Year Ended December 31, +2024 2023 2022 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 36,530 27,542 21,943 +Natural gas (Bcf) 155.8 123.4 99.3 +Total oil equivalent (MBOE) (1) +62,495 48,112 38,495 +Average daily production (BOE/d) (1) +170,751 131,813 105,465 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 75.89 $ 77.88 $ 96.32 +Oil, with realized derivatives (per Bbl) $ 75.89 $ 77.88 $ 92.87 +Natural gas, without realized derivatives (per Mcf) $ 2.38 $ 3.25 $ 7.98 +Natural gas, with realized derivatives (per Mcf) $ 2.47 $ 3.17 $ 7.15 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 4.91 $ 5.50 $ 7.33 +Lease operating $ 5.47 $ 5.06 $ 4.08 +Plant and other midstream services operating $ 2.74 $ 2.68 $ 2.48 +Depletion, depreciation and amortization $ 15.59 $ 14.90 $ 12.11 +General and administrative $ 2.04 $ 2.29 $ 3.02 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2024 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 36,265 263 — 2 36,530 +Natural gas (Bcf) 147.5 0.6 6.3 1.4 155.8 +Total oil equivalent (MBOE) (3) +60,856 361 1,046 232 62,495 +Percentage of total annual net production 97.4 % 0.6 % 1.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 99,086 719 — 3 99,808 +Natural gas (MMcf/d) 403.1 1.6 17.2 3.8 425.7 +Total oil equivalent (BOE/d) 166,273 986 2,859 633 170,751 +Average Sales Prices (4) +Oil (per Bbl) $ 75.90 $ 75.64 $ — $ 70.13 $ 75.89 +Natural gas (per Mcf) $ 2.40 $ 4.19 $ 1.95 $ 2.02 $ 2.38 +Total oil equivalent (per BOE) $ 51.05 $ 61.97 $ 11.67 $ 12.33 $ 50.31 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.87 $ 36.68 $ 6.10 $ 8.00 $ 6.23 +__________________ +(1) Includes 61 gross (41.0 net) wells from the Eagle Ford formation that were divested in 2024 and one well producing oil from the Austin Chalk formation in La Salle County, Texas that was divested in November 2024. +(2) Includes the Cotton Valley formation and shallower zones. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 27,264 276 — 2 27,542 +Natural gas (Bcf) 113.9 0.7 8.2 0.6 123.4 +Total oil equivalent (MBOE) (3) +46,253 390 1,373 96 48,112 +Percentage of total annual net production 96.1 % 0.8 % 2.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 74,697 755 — 5 75,457 +Natural gas (MMcf/d) 312.1 1.9 22.6 1.5 338.1 +Total oil equivalent (BOE/d) 126,720 1,068 3,761 264 131,813 +Average Sales Prices (4) +Oil (per Bbl) $ 77.90 $ 76.10 $ — $ 74.53 $ 77.88 +Natural gas (per Mcf) $ 3.32 $ 3.54 $ 2.23 $ 2.09 $ 3.25 +Total oil equivalent (per BOE) $ 54.10 $ 60.01 $ 13.39 $ 13.61 $ 52.91 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.99 $ 32.78 $ 4.59 $ 17.79 $ 6.19 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 21,585 355 — 3 21,943 +Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3 +Total oil equivalent (MBOE) (3) +36,550 501 1,383 61 38,495 +Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 59,139 971 — 9 60,119 +Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1 +Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465 +Average Sales Prices (4) +Oil (per Bbl) $ 96.34 $ 95.23 $ — $ 91.53 $ 96.32 +Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98 +Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 62.5 million BOE for the year ended December 31, 2024 increased 30% from our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023. This increased production was primarily attributable to the Ameredev Acquisition and to our delineation and development operations in the Delaware Basin throughout 2024, which offset declining production in the Eagle Ford shale and Northwest Louisiana. Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, as compared to 131,813 BOE per day for the year ended December 31, 2023. Our average daily oil production for the year ended December 31, 2024 was 99,808 Bbl of oil per day, an increase of 32% from 75,457 Bbl of oil per day for the year ended December 31, 2023. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf of natural gas per day, an increase of 26% from 338.1 MMcf of natural gas per day for the year ended December 31, 2023. +Our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023 increased 25% from our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022. This increased production was primarily due to the Advance Acquisition and to our delineation and development operations in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, as compared to 105,465 BOE per day for the year ended December 31, 2022. Our average daily oil production for the year ended December 31, 2023 was 75,457 Bbl of oil per day, an increase of 26% from 60,119 Bbl of oil per day for the year ended December 31, 2022. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf of natural gas per day, an increase of 24% from 272.1 MMcf of natural gas per day for the year ended December 31, 2022. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2024. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 85% in all wells that we operated at December 31, 2024. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +1,769 927.4 180 92.4 1,949 1,019.8 +South Texas: +Eagle Ford 31 30.3 — — 31 30.3 +Northwest Louisiana: +Haynesville — — 268 18.5 268 18.5 +Cotton Valley (2) +— — 66 39.0 66 39.0 +Area Total — — 334 57.5 334 57.5 +Total 1,800 957.7 514 149.9 2,314 1,107.6 +__________________ +(1) Includes 226 gross (91.6 net) vertical wells that were primarily acquired in multiple transactions. +(2) Includes the Cotton Valley formation and shallower zones. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2024, 2023 and 2022. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +17 +Table of Contents +At December 31, (1) +2024 2023 2022 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 361,842 272,277 196,289 +Natural Gas (Bcf) 1,498.2 1,126.8 962.6 +Total (MBOE) (3) +611,536 460,070 356,722 +Estimated proved developed reserves: +Oil (MBbl) 206,269 161,642 116,030 +Natural Gas (Bcf) 963.2 782.7 632.9 +Total (MBOE) (3) +366,797 292,097 221,507 +Percent developed 60.0 % 63.5 % 62.1 % +Estimated proved undeveloped reserves: +Oil (MBbl) 155,573 110,635 80,259 +Natural gas (Bcf) 535.0 344.0 329.7 +Total (MBOE) (3) +244,740 167,973 135,215 +Standardized Measure (4) (in millions) +$ 7,376.6 $ 6,113.5 $ 6,983.2 +PV-10 (5) (in millions) +$ 9,233.8 $ 7,704.1 $ 9,132.2 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2024 were $71.96 per Bbl for oil and $2.13 per MMBtu for natural gas, for the 12 months ended December 31, 2023 were $74.70 per Bbl for oil and $2.64 per MMBtu for natural gas and for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2024, 2023 and 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2024, 2023 and 2022 were $1.86 billion, $1.59 billion and $2.15 billion, respectively. +Our estimated total proved oil and natural gas reserves increased 33% from 460.1 million BOE at December 31, 2023 to 611.5 million BOE at December 31, 2024. This increase in proved oil and natural gas reserves was primarily attributable to the Ameredev Acquisition and our delineation and development operations in the Delaware Basin during 2024. We increased our total proved oil and natural gas reserves by 119.9 million BOE as a result of acquisitions and trades during 2024. We also added 99.9 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2024, of which 28.4 million BOE resulted from new well locations turned to sales during 2024 to establish proved developed reserves and 71.5 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2024. These increases were partially offset by net downward revisions of prior estimates for proved oil and natural gas reserves, including the removal of 8.2 million BOE resulting from the 4% decrease in oil prices and the 19% decrease in natural gas prices used to estimate total proved reserves at December 31, 2024, as compared to December 31, 2023, and the removal of 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of the 15.3 million BOE to proved reserves at a future date. These downward revisions at December 31, 2024 were partially offset by positive forecast updates of 21.7 million BOE. +Our proved oil reserves grew 33% from approximately 272.3 million Bbl at December 31, 2023 to approximately 361.8 million Bbl at December 31, 2024. Our proved natural gas reserves increased 33% from 1.13 Tcf at December 31, 2023 to 1.50 Tcf at December 31, 2024. Our proved reserves to production ratio at December 31, 2024 was 9.8, an increase of 2% from 9.6 at December 31, 2023. +18 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increased 21% from $6.11 billion at December 31, 2023 to $7.38 billion at December 31, 2024. The PV-10 of our total proved oil and natural gas reserves increased 20% from $7.70 billion at December 31, 2023 to $9.23 billion at December 31, 2024. The increases in our Standardized Measure and PV-10 are primarily a result of the 33% increase in our total proved oil and natural gas reserves at December 31, 2024, as compared to December 31, 2023, partially offset by the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2024, as compared to December 31, 2023. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2024 were $71.96 per Bbl and $2.13 per MMBtu, a decrease of 4% and 19%, respectively, as compared to average oil and natural gas prices of $74.70 per Bbl and $2.64 per MMBtu used to estimate proved reserves at December 31, 2023. Our total proved reserves were made up of 59% oil and 41% natural gas at both December 31, 2024 and 2023. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2024. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2023 292,097 +Extensions and discoveries 28,376 +Net acquisitions of minerals-in-place 59,293 +Revisions of prior estimates (5,072) +Production (62,495) +Conversion of proved undeveloped to proved developed 54,598 +As of December 31, 2024 366,797 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 26% from 292.1 million BOE at December 31, 2023 to 366.8 million BOE at December 31, 2024. We added 28.4 million BOE in proved developed reserves through extensions and discoveries during 2024, which resulted from new well locations drilled during 2024 to establish proved reserves. In addition, during 2024, we converted 54.6 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. We also increased our proved developed reserves by 59.3 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. Additionally, we realized approximately 5.1 million BOE in net downward revisions of prior estimates in 2024, most of which were attributable to the lower commodity prices used to estimate proved reserves at December 31, 2024, which resulted in shorter estimated economic lives for certain of our producing properties. These cumulative net increases of 137.2 million BOE to our proved developed reserves exceeded by 2.2 times our total oil and natural gas production of 62.5 million BOE in 2024. +Our proved developed oil reserves increased 28% from 161.6 million Bbl at December 31, 2023 to 206.3 million Bbl at December 31, 2024. Our proved developed natural gas reserves increased 23% from 782.7 Bcf at December 31, 2023 to 963.2 Bcf at December 31, 2024. Proved developed reserves constituted 60% of our total proved oil and natural gas reserves at December 31, 2024, as compared to 63% at December 31, 2023. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2024. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2023 167,973 +Extensions and discoveries 71,534 +Net acquisitions of minerals-in-place 60,583 +Revisions of prior estimates (752) +Conversion of proved undeveloped to proved developed (54,598) +As of December 31, 2024 244,740 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +19 +Table of Contents +Our proved undeveloped oil and natural gas reserves increased 46% from 168.0 million BOE at December 31, 2023 to 244.7 million at December 31, 2024. We added 71.5 million BOE in proved undeveloped reserves through extensions and discoveries during 2024, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2024. In addition, we increased our proved undeveloped reserves by 60.6 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. These increases were partially offset by net downward revisions of prior estimates for proved oil and natural gas reserves, including the removal of 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin and the removal of 2.1 million BOE for certain expense and pricing updates. These downward revisions were largely offset by positive forecast updates of 16.2 million BOE. During 2024, we also converted 54.6 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. +At December 31, 2024, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2024 within five years of booking these reserves. The following table sets forth, since 2021, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2021 23,965 96.6 40,071 $ 240,664 +2022 22,515 95.3 38,403 434,336 +2023 18,492 98.6 34,928 441,671 +2024 34,857 118.4 54,598 685,163 +Total 99,829 408.9 168,000 $ 1,801,834 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +20 +Table of Contents +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2024. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 360,396 1,474.8 606,196 $ 7,355.4 $ 9,207.3 +South Texas: +Eagle Ford 1,441 1.4 1,667 21.2 26.7 +Northwest Louisiana +Haynesville — 19.7 3,286 5.4 6.8 +Cotton Valley (5) +4 2.3 387 (5.6) (7.0) +Area Total 4 22.0 3,673 (0.2) (0.2) +Total 361,842 1,498.2 611,536 $ 7,376.6 $ 9,233.8 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2024 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2024 were approximately $1.86 billion. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes the Cotton Valley formation and shallower zones. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2024. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. +21 +Table of Contents +Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2024. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 271,300 156,900 56,700 41,800 328,000 198,700 +South Texas: +Eagle Ford 2,900 2,900 — — 2,900 2,900 +Northwest Louisiana: +Haynesville 16,200 8,900 — — 16,200 8,900 +Cotton Valley 15,700 14,800 — — 15,700 14,800 +Area Total (1) +18,500 17,300 — — 18,500 17,300 +Total 292,700 177,100 56,700 41,800 349,400 218,900 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2024 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2030 and beyond totals 2,400 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024. +Acres Acres Acres Acres Acres +Expiring 2025 Expiring 2026 Expiring 2027 Expiring 2028 Expiring 2029 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +12,700 7,500 14,800 8,000 16,700 14,100 5,200 5,200 4,600 4,600 +Total 12,700 7,500 14,800 8,000 16,700 14,100 5,200 5,200 4,600 4,600 +__________________ +(1) Approximately 56% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect in most cases until the cessation of production in commercial quantities. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of such lease. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2024, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of +22 +Table of Contents +ten years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2024, approximately 3% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2024, 2023 and 2022 . +Year Ended December 31, +2024 2023 2022 +Gross Net Gross Net Gross Net +Development Wells +Productive 253 106.9 222 84.1 138 61.4 +Dry — — — — — — +Exploration Wells +Productive (1) +9 4.9 24 16.9 20 11.0 +Dry — — — — — — +Total Wells +Productive (2) +262 111.8 246 101.0 158 72.4 +Dry — — — — — — +(1) All of these wells are extension wells. +(2) Includes three gross (1.5 net) vertical wells in 2024, one gross (0.5 net) vertical well in 2023 and three gross (1.6 net) vertical wells in 2022. +At December 31, 2024, we had a total of 65 gross (45.5 net) development wells and ten gross (7.9 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also generally deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted NGLs based on either a negotiated percentage of the proceeds that are generated from the sale of NGLs or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel and energy sources; weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions or conflicts in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; the threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; tariffs and trade restrictions; and overall worldwide economic +23 +Table of Contents +conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled or unscheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +24 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, acquire properties and provide competitive midstream services will depend upon our ability to conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Environmental +Emissions Mitigation +We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines that we expect to have sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities. +Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control and Data Acquisition (“SCADA”) equipment at a number of our larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require. +Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions. +Water Management +Using improving technologies, where feasible, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations. +25 +Table of Contents +Land Stewardship +When feasible, we attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S. Department of Interior Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, dunes sagebrush lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations. +During 2024, 96% of our gross operated oil production and 99% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water. +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing and setbacks, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. +Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions +26 +Table of Contents +having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. The NEPA evaluation process at the Department of the Interior has followed regulations issued by the Council on Environmental Quality (“CEQ”) for many years. However, recent court rulings, including a 2024 decision by the United States Court of Appeals for the District of Columbia, have held that CEQ lacks legal authority to issue binding regulations governing the NEPA process. In addition, following an executive order from the Trump administration, CEQ has announced that it is rescinding its NEPA regulations, and as a result, each government agency impacted by NEPA may be required to establish its own processes and procedures. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +In January 2021, the Biden administration issued executive orders limiting and delaying the issuance of new leases and drilling permits on federal lands (the “Biden Administration Federal Lease Orders”). The pause in issuing new leases was challenged in court, and the BLM ultimately continued to issue leases during the Biden administration. Furthermore, in January 2025, the Trump administration revoked the executive order from President Biden pausing new oil and gas leases on public lands. +In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under NEPA in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. BLM later announced that drilling permit approvals could be considered for the subject leases, provided that the process included additional time for public comments and objections. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits, is uncertain. +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the Environmental Protection Agency (the “EPA”) suggested increasing the value of the social cost of greenhouse gases from $51 per metric ton to $190 per metric ton, and in December 2023, the EPA used $190 per metric ton as the social cost of greenhouse gases in its final rule revising New Source Performance Standards (“NSPS”) and Emission Guidelines for greenhouse gas and volatile organic compound emissions in the oil and gas sector. As part of this final rulemaking, the EPA published a peer-reviewed report on the updated social cost of greenhouse gases estimates. However, in January 2025, the Trump administration revoked the Biden administration’s executive order regarding the social cost of greenhouse gases, withdrew the social cost of greenhouse gases estimates and directed the EPA administrator to consider issuing guidance eliminating the social cost of carbon calculation from any Federal permitting or regulatory decision. Future EPA rulemakings may reestablish the previous social cost of greenhouse gases estimates or incorporate new estimates developed in the future and potentially result in more stringent rules and regulations affecting the oil and gas sector. +In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In November 2023, the federal district court for the District of Columbia dismissed the case, holding that the environmental groups lacked standing. The environmental groups have appealed the district court’s ruling, and their appeal remains pending. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of +27 +Table of Contents +drilling permits, though the ultimate impact is uncertain given the Trump administration’s revocations of related executive orders. +In April 2024, the BLM finalized a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. Furthermore, following an executive order by the Trump administration, the Department of the Interior has announced it is evaluating whether to suspend, revise, or rescind the 2024 waste rule. The ultimate outcome of this process, including possible financial costs and any adverse impacts on our oil and natural gas operations, is uncertain. +Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed or been revoked, the impact of these and similar federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Pipeline Regulation +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. As part of the Ameredev Acquisition, we acquired crude oil gathering and transportation pipelines with origin points from Lea County, New Mexico to various interconnections with third parties (the “Trophy Pipeline System”). The Trophy Pipeline System is also subject to FERC jurisdiction. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with +28 +Table of Contents +FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System and the Trophy Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. To enact the changes outlined in the notice of proposed rulemaking, PHMSA enacted three separate rules (together known as the “Mega Rule”). The first part of the Mega Rule was finalized in October 2019 and requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In September 2023, PHMSA issued a proposed rule applicable to gas transmission and distribution and gathering pipelines, which would require updates to emergency response plans and other safety practices. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. +29 +Table of Contents +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +Underground Injection and Hydraulic Fracturing +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, have imposed additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible +30 +Table of Contents +linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the EPA and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On January 18, 2023, the EPA and the Corps jointly issued a final rule revising the definition of WOTUS that largely returned to the pre-2015 regulatory regime. On September 8, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands only to those that have a continuous surface connection to water bodies. On August 29, 2023, the EPA and the Corps jointly issued a final rule, which took effect immediately, aligning the regulatory definition of WOTUS with the Supreme Court’s ruling. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of +31 +Table of Contents +hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which included a range of measures designed to address climate change, including the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. However, the Trump administration has announced a change in course. In January 2025, the Trump administration issued an executive order directing the U.S. Ambassador to the United Nations to immediately submit formal written notification of the U.S.’s withdrawal from the Paris Agreement and any agreement, pact, accord or similar commitment made under the United Nations Framework Convention on Climate Change, which would include the Glasgow Climate Pact. +In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibit flaring in certain circumstances and require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. In November 2024, the New Mexico Court of Appeals upheld the ozone precursor rule, though this decision may be appealed. +In January 2025, the NMED announced that, due to budget constraints, the NMED Cabinet Secretary will issue a temporary emergency rule to suspend deadlines to issue air permits. Air permits are required for the construction of new oil and gas production facilities or the modification of existing facilities in New Mexico. Whether this announcement will result in meaningful delays or cancelation of our permit applications is uncertain. Any interruption in our ability to timely obtain air permits could result in delays in or an inability to proceed with our development plans for our oil and natural gas operations. +32 +Table of Contents +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. The Biden administration started a number of climate and environmental justice initiatives at the federal level. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort was designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA began implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. It is expected that policies relating to environmental matters will change under the Trump administration, but it is too soon to predict what the ultimate impact of the change in administration will be. +On March 8, 2024, the EPA issued a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources. Additionally, on November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. As another example, in April 2024, the EPA issued a final consent decree that established a December 10, 2024 deadline for the EPA to review and propose revisions to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. The EPA has not yet proposed any such revisions. +Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. On May 20, 2024, the USFWS issued a final rule listing the dunes sagebrush lizard as endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate and our ability to maximize production from our leases may be adversely impacted by these restrictions. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more +33 +Table of Contents +stringent environmental laws and regulations will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The overall trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable or unwilling to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance other than with respect to our midstream business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2024, we had 452 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2024, for example, our employees completed approximately 22,500 hours of continuing education and study, equating to approximately 50 hours per employee. We also have a leadership program that fosters the development and growth of many of our staff with meetings and opportunities to enhance their leadership skills. +34 +Table of Contents +We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and our experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +35 +Table of Contents +Item 1A. Risk Factors. +Summary of Risk Factors +The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition, results of operations and cash flows. You should read this summary together with the more detailed risk factors contained below. +Risks Related to our Financial Condition +• Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. +• Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. +• We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and in the Middle East. +• Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. +• Our oil and natural gas reserves are estimated, and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +• The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +• Approximately 41% of our total proved reserves at December 31, 2024 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +• Unless we replace our oil and natural gas reserves, our reserves and production will decline. +• We may be required to write down the carrying value of our proved properties under accounting rules. +• Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +• Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. +• Our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. +• We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. +• We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +• Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +Risks Related to our Liquidity +• We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. +• The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +• The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations. +• Our credit rating may be downgraded, which could reduce our financial flexibility. +• Dividend payments are at the discretion of our Board of Directors and subject to numerous factors. +Risks Related to our Operations +• Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk. +• Our operations are subject to operational hazards and risks, and insurance against all such risks is not available to us. +• Our reserves and production are concentrated in a few core areas. +• There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. +• Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. +• Multi-well pad drilling may result in volatility in our operating results. +• The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. +• We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. +• Midstream projects are subject to risks of construction delays and cost over-runs. +36 +Table of Contents +• Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. +• The seismic data and other technologies we use cannot eliminate exploration risk. +Risks Related to Third Parties +• Financial difficulties encountered by purchasers, operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +• The marketability of our production is dependent upon gathering, processing and transportation facilities. +• We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. +• San Mateo’s long-term success depends on its ability to obtain new sources of products, which depends on certain factors beyond its control. +• Certain of our long-term contracts require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and may limit our ability to use other service providers. +• We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +• Competition in our industry is intense, and our competitors may use superior technology and data resources. +• Strategic relationships upon which we may rely are subject to change. +• We have limited control over activities on properties we do not operate. +Risks Related to Laws and Regulations +• Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations. +• We are subject to government regulation, including complex environmental laws, which could require significant expenditures. +• We are subject to tax laws and may become subject to new taxes, or tax deductions currently available to us may be eliminated or reduced. +• Legislation and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs and additional operating restrictions or delays, and the physical effects of climate change could disrupt our production and cause us to incur significant costs. +• New climate disclosure rules proposed by the SEC or states in which we have operations or do business could increase our costs of compliance. +• We may incur significant costs and liabilities resulting from compliance with emissions or pipeline safety regulations. +• A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets. +• The rates of our regulated assets are subject to review and reporting by federal regulators. +• Should we fail to comply with FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +• Derivatives legislation adopted by Congress could limit our ability to hedge risks associated with our business. +• Changes in U.S. foreign trade policies may materially and adversely affect our business, operations and financial condition. +Risks Related to Our Common Stock +• The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +• Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect us. +• Future sales and offerings of our common stock could depress the price of our common stock. +• Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. +• The issuance of preferred stock could diminish the rights of holders of our common stock. +General Risk Factors +• We may have difficulty managing growth in our business. +• The loss of any key personnel or Board member could disrupt our business operations. +• A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +• Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. +• We operate in a litigious environment and may be involved in legal proceedings. +37 +Table of Contents +Risks Related to our Financial Condition +Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations. +The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2024, oil prices averaged $75.76 per Bbl, as compared to $77.60 per Bbl in 2023, ranging from a high of $86.91 per Bbl in early April to a low of $65.75 per Bbl in mid-September, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2024, natural gas prices averaged $2.40 per MMBtu, as compared to $2.66 per MMBtu in 2023, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2024, natural gas prices ranged from a low of $1.58 per MMBtu in late March to a high of $3.95 per MMBtu in late December. +The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following: +• the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; +• the actions of OPEC+ and state-controlled oil companies; +• the prices and availability of competitors’ supplies of oil, natural gas and NGLs; +• the price and quantity of foreign imports; +• the impact of U.S. dollar exchange rates; +• domestic and foreign governmental regulations and taxes; +• speculative trading of oil and natural gas futures contracts; +• the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; +• the availability of refining capacity; +• the prices and availability of alternative fuel and energy sources; +• weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; +• political conditions or conflicts in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; +• the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; +• domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; +• the threat of terrorism and the impact of military action and civil unrest; +• public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing activities; +• the level of global oil, natural gas and NGL inventories and exploration and production activity; +• the impact of energy conservation efforts; +• technological advances affecting energy consumption; +• tariffs and trade restrictions; and +• overall worldwide economic conditions. +These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not +38 +Table of Contents +pursuant to long-term fixed price contracts. Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relation to each other. +Declines in oil, natural gas or NGL prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. Should oil, natural gas or NGL prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. +Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. +Inflation in the U.S. has become much more significant in recent years. Since 2022, we have experienced significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Supply and demand fundamentals have been aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as related actions of the U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps. Should oil and natural gas prices remain at their current levels or increase, we expect to be subject to additional supply chain constraints and service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughout the U.S. and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flows. +We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and in the Middle East and the related humanitarian crises on the global economy, energy markets, geopolitical stability and our business. +Although our leasehold acreage is located primarily in the Delaware Basin, the broader consequences of the conflicts between Russia and Ukraine and in the Middle East, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of either conflict’s effect on our business and results of operations as well as on the global economy and energy markets. +Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth. +Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement, the San Mateo Credit Facility or otherwise may not be sufficient to fund all of our future capital expenditures or future acquisitions. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. +Our cash flows from operations and access to capital are subject to a number of variables, including: +• our estimated proved oil and natural gas reserves; +• the amount of oil and natural gas we produce; +• the prices at which we sell our production; +• the costs of developing and producing our oil and natural gas reserves; +• the costs of constructing, operating and maintaining our midstream facilities; +39 +Table of Contents +• our ability to attract third-party customers for our midstream services; +• our ability to acquire, locate and produce new reserves; +• the ability and willingness of banks or other financial institutions to lend to us; and +• our ability to access the equity and debt capital markets. +In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak or resurgence of contagious or pandemic diseases, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. +If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to develop our properties, pay for higher service costs, fund acquisitions, increase our rate of growth, or expand our midstream operations, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. +Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of this technical data and the associated interpretations can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: +• the quality and quantity of available data; +• the interpretation of that data; +• the judgment of the persons preparing the estimate; and +• the accuracy of the assumptions used. +The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of certain of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. +Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves. +The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. +It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated +40 +Table of Contents +discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: +• actual prices we receive for oil and natural gas; +• actual costs and timing of development and production expenditures; +• the amount and timing of actual production; and +• changes in governmental regulations or taxation. +In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. +Approximately 41% of our total proved reserves at December 31, 2024 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. +At December 31, 2024, approximately 40% of our total proved reserves were undeveloped and approximately 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. +Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows. +The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. +We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition. +There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have: +• downward adjustments to our estimated proved reserves; +• increases in our estimates of development costs; or +• deterioration in our exploration and development results. +We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. +41 +Table of Contents +Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. +To manage our exposure to price risk, including price differential risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap, as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged. +In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. +Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. +A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows. +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. +Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. +Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in the latter part of 2024 and early in 2025, these price differentials for natural gas remain wide and could widen further in future periods. Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. +A component of our growth may come through acquisitions, and our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. +We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted. +42 +Table of Contents +In addition, the success of our acquisitions will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the acquired assets and operations into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of our acquisitions. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. Difficulties in integrating our acquisitions into our company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others: +• the inability to successfully integrate our acquisitions operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from such acquisitions; +• not realizing anticipated operating synergies; and +• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with such acquisitions. +Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. +We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the borrowing of funds, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. +We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations. +Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We may not perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. Even when problems with a property or asset are identified, the seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other risks and liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. +We may incur losses or costs as a result of title deficiencies in the properties in which we invest. +If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost. +It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest. +Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no +43 +Table of Contents +obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. A failure to cure any title defects may delay or prevent us from utilizing the associated leasehold right or mineral interest, which may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows. +Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. +From time to time, we may sell a portion of an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us. +Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. +Risks Related to our Liquidity +We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. +Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. +If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations. +We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs. +As of February 18, 2025, the maximum facility amount under the Credit Agreement was $3.50 billion, the borrowing base was $3.25 billion and our elected borrowing commitment was $2.25 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). At February 18, 2025, we had available borrowing capacity of approximately $1.55 billion under our Credit Agreement (after giving effect to outstanding letters of credit and subject to our compliance with the covenants noted below). +As of February 18, 2025, the facility amount under the San Mateo Credit Facility was $800.0 million, and San Mateo had available borrowing capacity of approximately $244.0 million (after giving effect to outstanding letters of credit and subject to +44 +Table of Contents +San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.05 billion. +In the future, subject to the restrictions in the indentures governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. +A high level of indebtedness could affect our operations in several ways, including: +• requiring a significant portion of our cash flows to be used for servicing our indebtedness; +• increasing our vulnerability to general adverse economic and industry conditions; +• placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; +• restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and +• increasing the risk that we may default on our debt obligations. +The borrowing base under our Credit Agreement is subject to periodic redetermination. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results. +We are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. +Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a loan based on the secured overnight financing rate administered by the Federal Reserve Bank of New York (“SOFR”). If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Overnight Bank Funding Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the Daily Simple SOFR (as defined in the Credit Agreement) on such day, plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% depending on the level of borrowings under the Credit Agreement. If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. +Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +Interest rates rose significantly during 2022 and remained elevated throughout 2023 and 2024 as the Federal Reserve sought to control inflation. Interest rates may remain high during 2025. Our Credit Agreement and the San Mateo Credit +45 +Table of Contents +Facility have floating rates tied to SOFR or other interest rate benchmarks that generally increase or decrease alongside changes in the federal funds rates. As a result, interest expense on our existing floating rate debt rose during 2022 and 2023, remained high during 2024 and may remain high during 2025. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. +The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions. +Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes contain, and any future indebtedness we or San Mateo incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our and San Mateo’s ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that restrict our or San Mateo’s ability to: +• incur or guarantee additional debt or issue certain types of preferred stock; +• declare or pay dividends or distributions or redeem, repurchase or retire our capital stock or subordinated indebtedness; +• transfer or sell assets; +• make certain investments; +• create certain liens; +• enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indentures governing our outstanding senior notes) to us; +• consolidate, merge or transfer all or substantially all of our assets; +• engage in transactions with affiliates; and +• create unrestricted subsidiaries. +A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes. For example, our Credit Agreement requires us to comply with certain financial covenants, including maintaining a specified debt to EBITDA ratio and current ratio. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with these covenants. +Similarly, the San Mateo Credit Facility requires San Mateo to comply with certain financial covenants, including maintaining a specified debt to EBITDA ratio and interest coverage ratio. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. For a summary of these financial restrictions and other covenants in our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes, see Note 7 to the consolidated financial statements in this Annual Report. +Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indentures governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities. +Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations. +In March 2020, our corporate credit ratings from S&P Global Ratings and Moody’s Investors Service were downgraded in significant part due to the sudden decline in oil prices in early 2020. These corporate credit ratings were subsequently upgraded, and as of February 18, 2025, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “BB-,” “Ba3” and “BB-,” respectively. We cannot guarantee you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future. +Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected. +46 +Table of Contents +The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock. +In each of the first, second and third quarters of 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock. In February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a quarterly cash dividend of $0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025. We intend to continue to pay a quarterly dividend in the future pursuant to the dividend policy adopted by our Board. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available. +We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indentures governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price. +Risks Related to our Operations +Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business. +Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. +If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including: +• general economic and industry conditions, including the prices received for oil and natural gas; +• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; +• limited access to electrical power sources or other infrastructure used in our operations; +• potential drainage of oil and natural gas from our properties by operations on adjacent properties; +• the existence or magnitude of faults or unanticipated geological features; +• loss of or damage to oilfield development and service tools; +• accidents, equipment failures or mechanical problems; +• title defects of the underlying properties; +• increases in severance taxes; +47 +Table of Contents +• adverse weather conditions that delay drilling activities or cause producing wells to be shut in; +• inflation in exploration, drilling, completion and production costs; +• domestic and foreign governmental regulations; and +• proximity to and capacity of gathering, processing, transportation and disposal facilities. +Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include: +• landing our wellbore in the desired drilling zone; +• staying in the desired drilling zone while drilling horizontally through the formation; +• running our casing the entire length of the wellbore; +• fracture stimulating the planned number of stages; +• drilling out the plugs between stages following hydraulic fracturing operations; and +• being able to run tools and other equipment consistently through the horizontal wellbore. +Each of these risks is magnified in wells with longer laterals. In 2024, the average completed lateral length for operated wells turned to sales was approximately 9,300 feet. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. +Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue. +There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including: +• natural disasters; +• adverse weather conditions, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; +• domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; +• loss of drilling fluid circulation; +• blowouts where oil or natural gas flows uncontrolled at a wellhead; +• cratering or collapse of the formation; +• pipe or cement leaks, failures or casing collapses; +• damage to pipelines, processing plants and disposal wells and associated facilities; +• fires or explosions; +• releases of hazardous substances, toxic gases such as hydrogen sulfide or other waste materials; +• pressures or irregularities in formations; and +• equipment failures or accidents. +In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. +Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. The protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased +48 +Table of Contents +expenses or the curtailment of our oil and natural gas production. In addition, if such a seismic event occurred in the area of the Company’s or San Mateo’s operations, the Company or San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. Any such further events could adversely impact our and San Mateo’s revenues and cash flows. +There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Marlan Processing Plant and the Black River Processing Plant. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant or the Marlan Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. +In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected. +Insurance against all operational risks is not available to us. +Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business. +Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 97% of our total oil and natural gas production for 2024 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2025 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well opportunities in our South Texas and Haynesville shale positions. +The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled or unscheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms, floods and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the +49 +Table of Contents +inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut-ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather. +Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows. +There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value. +As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows. +Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. +Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators. +Multi-well pad drilling may result in volatility in our operating results. +We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity. +The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in +50 +Table of Contents +the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. Further, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures being experienced throughout the United States and global economy may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows. +In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows. +If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired. +We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including the use of fresh water in such operations, or (ii) disposal of waste, including the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity. +From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity, financial condition and the ability of San Mateo to attract third-party customers. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions. +Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially +51 +Table of Contents +different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. +At December 31, 2024, we had leasehold interests in approximately 39,400 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2030. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. +The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows. +We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. +Risks Related to Third Parties +Financial difficulties encountered by our oil, natural gas and NGL purchasers, third-party operators, third-party customers or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. +We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For each of the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that collectively accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows. +In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate and from San Mateo’s customers. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be adversely affected. +The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue. +The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural +52 +Table of Contents +gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. +We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, treating, compression or processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. +The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. While we have entered into natural gas processing, treating, compression and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. For example, in the fourth quarter of 2024, we experienced temporary natural gas pipeline and processing interruptions due to maintenance and constraints that are estimated to have resulted in approximately 3,000 BOE per day of less production. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2025. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. +We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows. +We own and operate substantially all of our midstream assets in Eddy County, New Mexico and Loving County, Texas and a significant proportion of our midstream assets in Lea County, New Mexico through San Mateo, and we have and may continue to enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control. In addition, if our joint venture partners do not fulfill their contractual, financial and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for certain joint ventures and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depend on its ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s control. Any decrease in supplies to their midstream facilities could adversely affect San Mateo’s business and operating results. +San Mateo’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum +53 +Table of Contents +volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital. +We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers. +From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering, treating, compression or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo and its subsidiaries, including Pronto. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2024, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $1.50 billion over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. +Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, including our midstream business, even if such service providers are able to offer us more favorable pricing or more efficient service. +We do not own all of the land on which our midstream assets are located, which could disrupt our operations. +We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford. +Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural gas and to secure trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected. +In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to a competitive labor market, inflation and other factors, and may increase substantially in the future. We may not be able to compete +54 +Table of Contents +successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. +Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations. +Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. +To develop our business, we endeavor to use the business relationships of our management and Board to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. +We have limited control over activities on properties we do not operate. +We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: +• the timing and amount of capital expenditures; +• the operator’s expertise and financial resources; +• the rate of production of reserves, if any; +• approval of other participants in drilling wells; and +• selection and implementation or execution of technology. +In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. +Risks Related to Laws and Regulations +Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands. +At December 31, 2024, Matador held approximately 198,700 net leasehold and mineral acres in the Delaware Basin, primarily in Eddy and Lea Counties, New Mexico and in Loving, Ward and Winkler Counties, Texas, of which approximately 65,500 net acres, or about 33%, was on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are +55 +Table of Contents +subject to change. For example, on August 16, 2022, H.R. 5376, commonly known as the Inflation Reduction Act of 2022 (the “IRA”), was enacted. Pursuant to the IRA, the royalty rate for federal leases issued on or after August 16, 2022 was increased to 16.67 percent. On April 23, 2024, the BLM issued a final rule that revised the BLM’s oil and gas leasing regulations, including aligning royalty rates, rentals and minimum bids with the IRA, and updated the bonding requirements for leasing, development and production. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits, though the ultimate impact is uncertain given the Trump administration’s revocations of related executive orders. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. +Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. This process, including any additional requirements that may be implemented or litigation regarding the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. See “Business—Regulation—Oil and Natural Gas Regulation.” +We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures. +The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. A change in the presidential administration, as well as a closely divided Congress, may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for: +• personal injuries; +• property damage; +• containment and clean-up of oil, produced water and other spills; +• venting, flaring or other emissions; +• management and disposal of hazardous materials; +• remediation, clean-up costs and natural resource damages; and +• other environmental damages. +We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations related to the environment have +56 +Table of Contents +changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant Nationwide Permits (“NWPs”) as such potential permit coverage relates to activities in the oil and natural gas sector, or the federal government could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA). +Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. For example, on March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of southeastern New Mexico where we operate. On May 20, 2024, the USFWS issued a final rule listing the dunes sagebrush lizard as endangered. We participate in candidate conservation agreements for the lesser prairie-chicken, as well as the dunes sagebrush lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. The listing of the dunes sagebrush lizard as endangered, participation in such candidate conservation agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.” +We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows. +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +Historically, we have generated and carried forward net operating losses (“NOL”) in amounts sufficient to offset substantially all of our taxable income and, thus, have not incurred material federal or state income tax liabilities. As of December 31, 2022, we had utilized all of our federal NOL carryovers. Our federal and state income tax liabilities in 2025 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods. +Additionally, the IRA contains a number of revisions to the Internal Revenue Code, including a 15% corporate minimum income tax for certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending before the corporation’s current tax year. The impact of the 15% corporate minimum tax will depend on our results of operations each year. While we do not expect such minimum tax to have any immediate material impact, we will continue to evaluate its future impact as further information becomes available. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The passage of any such legislation or any other similar change in U.S. federal income or state tax law could +57 +Table of Contents +affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands, but these rules never became effective. These rules were rescinded by rule in December 2017. The rescission was challenged, and the challenge remains pending before the Ninth Circuit Court of Appeals. +Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders, if passed at the local, state or federal level could limit our operations. +The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. +The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, have imposed additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. See “Business—Regulation—Underground Injection and Hydraulic Fracturing.” +While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. See “Business—Regulation—Environmental, Health and Safety Regulation.” +58 +Table of Contents +Increased seismicity in areas in which we operate could result in additional regulation and restrictions on the use of injection wells by us or by third parties whom we may contract with to dispose of produced water. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. Any one or more of these developments may result in operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could adversely impact our business, cash flows and results of operations and could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays. +Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. However, in January 2025, the Trump administration issued an executive order directing the EPA to re-evaluate the legality and continuing applicability of the endangerment finding. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. In addition, the United States has at times been a party to certain international agreements, pacts and other commitments designed to address climate change and reduce greenhouse gas emissions, including the Paris Agreement and the Glasgow Climate Pact. For further discussion of these international commitments, see “Business—Regulation—Environmental, Health and Safety Regulation.” +On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and, for the first time ever, impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels. Further, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on methane and greenhouse gas emissions from new and existing sources in the oil and natural gas industry. On March 8, 2024, the EPA issued a final rule to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA and requires state-level environmental regulators to create new emissions restrictions for existing sources as well. On November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. The EPA has begun adopting and implementing a comprehensive suite of regulations to restrict greenhouse gas emissions under existing provisions of the CAA and the recent authority of the IRA. In addition, some states, including New Mexico, have implemented rules and regulations relating to greenhouse gas emissions. For further discussion of these federal and state regulations, see “Business—Regulation—Environmental, Health and Safety Regulation.” +In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes, droughts, floods and freezes), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects, impacts on our workforce, supply chain or distribution chain and increased costs for, or difficulty procuring consistent levels of, insurance coverage in the aftermath of such effects. Any future exploration and development activities and equipment could also be adversely affected by severe weather conditions such as hurricanes or freezing temperatures, which may cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. Such severe weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream +59 +Table of Contents +companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our Operations—If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. +Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have a material adverse effect on our business, financial condition and results of operations. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. +Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have identified climate change as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, promoting energy efficiency or the development and consumption of alternative forms of energy or prohibiting or restricting oil and natural gas development activities in certain areas, have been, or may in the future be, proposed and/or promulgated. The Biden administration issued multiple executive orders pertaining to environmental regulations and climate change, which established climate change as a primary foreign policy and national security consideration, prioritized achieving net-zero greenhouse gas emissions by or before 2050 and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. It is anticipated that the policy of the Trump administration will reduce the focus on climate change and environmental justice at the federal level, but it is too soon to predict what overall effects the change in administration will have on these issues. As of January 2025, the Trump administration has revoked multiple Biden administration executive orders regarding climate change. For further discussion of these executive orders and other legislative and regulatory developments regarding climate change, see “Business—Regulation—Oil and Natural Gas Regulation.” +In any event, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes. +New climate disclosure rules adopted by the SEC or states in which we have operations or do business could increase our costs of compliance and adversely impact our business. +On March 6, 2024, the SEC adopted new rules that require significantly expanded climate-related disclosures in SEC filings, including certain climate-related risks, climate-related metrics and greenhouse gas emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements (the “SEC Climate Disclosure Rules”). The SEC Climate Disclosure Rules include certain phase-in compliance dates for disclosure of material Scope 1 and 2 greenhouse gas emissions. As adopted, large accelerated filers such as us would be obligated to disclose material Scope 1 and 2 greenhouse gas emissions beginning with their annual reports covering fiscal years that begin in 2025. However, on April 4, 2024, the SEC issued an order staying implementation of the SEC Climate Disclosure Rules pending judicial review of various legal challenges to the rules, which were consolidated into the Eighth Circuit Court of Appeals. On February 11, 2025, the SEC notified the Eighth Circuit Court of Appeals of a statement issued by the SEC’s Acting Chairman regarding, among other things, the fact that the majority of current SEC Commissioners had previously voted against adopting the SEC Climate Disclosure Rules and requested that the Eighth Circuit Court of Appeals delay certain aspects of the litigation to provide time for the SEC to deliberate and determine the appropriate next steps. Accordingly, while we are currently assessing the SEC Climate Disclosure Rules, the outcome of these legal challenges is uncertain, including with respect to the content of any portion of the SEC Climate Disclosure Rules that may be upheld and the ultimate timing of required compliance with such +60 +Table of Contents +rules, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the SEC Climate Disclosure Rules. In addition, in the absence of federal action, states may propose and adopt climate disclosure requirements. +In the event the SEC Climate Disclosure Rules go into effect or states in which we operate or do business adopt climate disclosure requirements, we could incur significant additional costs relating to the assessment and disclosure of climate-related risks, including costs relating to monitoring, collecting, analyzing and reporting the new metrics and implementing systems and procuring additional internal and external personnel with the requisite skills and expertise to serve those functions. These additional costs or changes in operations could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also face increased litigation risks related to disclosures made pursuant to these regulations. In addition, enhanced climate disclosure requirements could accelerate the trend of certain investors and lenders restricting or seeking more stringent conditions with respect to their investments in carbon-intensive sectors. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient. +New regulations on all emissions from our operations could cause us to incur significant costs. +In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the NSPS and NESHAP programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. In April 2024, the EPA issued a final consent decree that established a December 10, 2024 deadline for the EPA to review and propose revisions to the NESHAP for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. The EPA has not yet proposed any such revisions. The EPA finalized a more stringent National Ambient Air Quality Standard for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, BLM issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules were designed to limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under Federal leases. Under the authority of the IRA, on April 10, 2024, BLM finalized new regulations to reduce the waste of natural gas from venting, flaring and leaks during oil and natural gas production activities on Federal and Indian leases. These rules are expected to result in an increase to our operating costs and changes in our operations. In December 2023, the EPA issued final NSPS updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. The EPA issued a final rule on October 22, 2024, removing the affirmative defense for violations caused by malfunctions from the NESHAP for the oil and natural gas production source category and natural gas transmission and storage source category. On November 18, 2024, the EPA published a final rule under authority of the IRA that imposes a waste emissions charge on large emitters of waste methane from the oil and gas sector. Multiple states have filed suit against the EPA in the United States Court of Appeals for the District of Columbia claiming that the waste emissions charge exceeds the agency’s statutory authority, and various proposals have been advanced in Congress to either repeal the waste charge portion of the IRA or to reverse the EPA’s implementing regulations through the Congressional Review Act. As a result of this continued regulatory focus, these and any future federal and state regulations of the oil and natural gas industry could result in increased compliance costs for our operations. +We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations. +Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to such rules. PHMSA also recently finalized rulemaking to expand existing integrity management, reporting and records retention, and safety requirements to certain natural gas transmission lines. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of +61 +Table of Contents +such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. +Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. +A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, and our Trophy Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Lea County, New Mexico to various interconnects with third parties, are subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. +The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System transport crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows. +In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System, the Trophy Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC. +Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. +Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System and Trophy Pipeline System do transport crude oil in interstate commerce and, therefore, are subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. +Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business. +The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and +62 +Table of Contents +regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. For example, the CFTC has proposed, but not finalized, rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. +If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. +Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. +Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. +Changes in U.S. foreign trade policies, including the imposition of additional tariffs and other trade barriers, and efforts to withdraw from or materially modify international trade agreements, may materially and adversely affect our business, operations and financial condition. +Changes in U.S. foreign trade policies, including as a result of the second Trump administration, could lead to the imposition of additional trade barriers and tariffs on the foreign import of certain materials and products. For example, effective February 4, 2025, the U.S. government implemented an additional tariff on goods being imported from China and announced additional tariffs for goods imported into the U.S. from Mexico and Canada beginning in March 2025. In addition, from time to time, certain leaders in the U.S. government, including in the Trump administration, have indicated a willingness to revise, renegotiate or terminate various existing bilateral and multilateral trade agreements. We cannot predict what additional changes to trade policy will be made by the Trump administration or Congress, including whether existing tariff policies will be maintained or modified, what products may be subject to such policies or whether the entry into new bilateral or multilateral trade agreements will occur, nor can we predict the effects that any such changes would have on our business. However, such steps, if adopted, could increase our costs and adversely impact our business and operations. In addition, changes in U.S. trade policy have resulted, and could again result, in reactions from U.S. trading partners, including adopting responsive trade policies. For example, in response to the U.S. government’s additional tariff on imports from China, on February 4, 2025, the Chinese government announced that it would implement a tariff on certain goods being imported into China from the U.S. There can be no assurance that such changes in U.S. or foreign trade policy or in laws and policies governing foreign trade, and any resulting negative sentiments towards the United States as a result of such changes, would not materially and adversely affect our business, financial condition and results of operations. +Risks Related to Our Common Stock +The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. +Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2024, our stock price fluctuated between a high of $71.08 and a low of $47.15. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. +Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: +• our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; +• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; +• changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; +• declaration of dividends or adjustments to our dividend policy; +63 +Table of Contents +• speculation in the press or investment community; +• announcement or consummation of acquisitions, dispositions or joint ventures by us; +• public reaction to our operations or plans, press releases, announcements and filings with the SEC; +• the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; +• the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations; +• sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; +• general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; +• domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; +• the realization of any of the risk factors presented in this Annual Report; +• the recruitment or departure of key personnel; +• commencement of, involvement in or unfavorable resolution of litigation; +• the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; +• changes in market valuations of companies similar to ours; and +• domestic and international economic, legal and regulatory factors unrelated to our performance. +Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price. +Attention from governmental and regulatory bodies, investors, consumers and other stakeholders on ESG practices, together with changes in consumer, industrial and commercial behavior, investor and societal expectations on companies to address climate change and to make voluntary disclosures related to climate change and sustainability, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons and the use of products manufactured with, or powered, by hydrocarbons, may result in the enactment of climate and ESG-related regulations, policies and initiatives at the government, regulator, corporate and/or investor community levels; technological advances with respect to the generation, transmission, storage and consumption of energy; and the development of, and increased demand from consumers for, lower-emission products and services. These developments may in the future result in increased costs (including increased costs associated with compliance, shareholder engagement, contracting and insurance) and reduced demand for products manufactured with, or powered by, petroleum products, as well as the demand for our products and services. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. +In addition, negative perceptions regarding our industry and reputational risks, including perceptions related to the sufficiency of our ESG program (which may include policies, practices and extralegal objectives related to climate change, environmental stewardship, social responsibility and corporate governance), may in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. In particular, certain segments of the investor community have at times expressed negative sentiment towards investing in the oil and natural gas industry. There have also been efforts in recent years to influence the investment community, including investment advisors, investment fund managers, pension funds, sovereign wealth funds, university endowments, individual investors and family foundations, to divest, or limit investment in, fossil fuel equities. As a result, some investors have adopted policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors and asset managers, both domestically and internationally, have published ESG guidelines and disclosure standards that companies in which they invest are expected to adopt or follow. +Certain other stakeholders have pressured commercial and investment banks and other capital providers to stop or limit funding of oil and natural gas projects and have pressured insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Institutional lenders that provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. With the continued volatility in oil and natural gas prices and elevated interest rates, which have increased the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale plays. This may also result in an increase in our expenses and a reduction of revenues and available capital funding for potential development projects, further +64 +Table of Contents +impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected. +In addition, shareholder activism has been recently increasing in the oil and gas industry, and shareholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have an adverse effect on our stock price and our access to and costs of capital. +Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock. +The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. +We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. +Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. +As of February 18, 2025, our directors and executive officers beneficially owned approximately 5.8% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. +Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders. +Our Board is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. +Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders. +General Risk Factors +We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. +65 +Table of Contents +Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team and the members of our Board, and the loss of any key personnel or Board member could disrupt our business operations. +Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. +We have an active Board that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. +It has also been widely reported in the press and elsewhere that businesses have faced a more challenging hiring environment since the onset of the COVID-19 pandemic and the subsequent recovery, which has resulted in increased costs to attract skilled labor, such as higher wages or costs for contractors. We may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected. +A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. +Our business, like the oil and natural gas industry in general, is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities, including technologies that are managed by third-party service providers or other providers to our industry on whom we directly or indirectly rely to help us collect, host or process information. We depend on such digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our SCADA systems, control important processes and facilities that are critical to our operations. +While we and our third-party service providers commit resources to the design, implementation and monitoring of our information systems, there is no guarantee that these security measures will provide absolute security. Despite these security measures, we may not be able to anticipate, detect or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launch, and because attackers are increasingly using technologies designed to circumvent controls and avoid detection. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, ransomware or other malware, phishing or social engineering schemes or attacks or other cybersecurity threats or attacks, possible consequences include financial losses, damage to our reputation and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. In addition, any failure of our third-party providers’ computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business. +While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our or our third-party providers’ systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary or other sensitive information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, disruptions of our current or planned business operations or transactions, damage to our reputation or financial loss. Additionally, costs for insurance may also increase as a result of cybersecurity threats, and insurance against losses relating to cyber incidents may become more difficult to obtain. +As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and further enhance our protective systems or to investigate and remediate any vulnerabilities. In addition, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, mitigation and notification, which could lead to increased regulatory compliance costs, insurance coverage cost or +66 +Table of Contents +capital expenditures. Any failure by us to comply with any additional regulations could result in significant penalties and liability to us, and we cannot predict the potential impact to our business or the energy industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating to cybersecurity issues. +Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders. +Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition of the Company or other change in control transaction that our shareholders may consider favorable. These provisions include: +• authorization for our Board to issue preferred stock without shareholder approval; +• a classified Board so that not all members of our Board are elected at one time; +• the prohibition of cumulative voting in the election of directors; and +• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. +Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. +We operate in a litigious environment and may be involved in legal proceedings that could have a material adverse effect on our results of operations and financial condition. +Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 1C. Cybersecurity. +Risk Management and Strategy +The Company recognizes the importance of developing, implementing and maintaining cybersecurity measures to better safeguard our information systems and protect the confidentiality, integrity and availability of our data. +Managing Material Risks and Integrated Overall Risk Management +The Company has integrated cybersecurity into our broader risk management framework. Our risk management team works closely with our IT department to evaluate and address cybersecurity risks in alignment with our business objectives and operational needs. The Company requires the Board and employees to complete cybersecurity training related to the physical security of assets, data privacy and other information security policies and procedures. +Engage Third Parties on Risk Management +Recognizing the complexity and evolving nature of cybersecurity threats, the Company engages with a range of external experts, including cybersecurity consultants in evaluating and testing our risk management systems. Our collaboration with these third parties includes regular audits, threat assessments, penetration tests and consultation on security enhancements. +Oversee Third-Party Risk +67 +Table of Contents +Because we are aware of the risks associated with third-party vendors, service providers and business partners, we have implemented processes to oversee and manage these risks. We conduct initial risk assessments of third-party providers before engagement. These assessments include due diligence reviews of third parties that have access to our networks, confidential information and information systems in order to assess the risks from cybersecurity threats. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third parties. +Risks from Cybersecurity Threats +As of February 18, 2025, we were not aware of any cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations or financial standing. However, there can be no assurance that our cybersecurity processes will prevent or mitigate cybersecurity incidents or threats and that our efforts will always be successful. For further discussion regarding our cybersecurity risks, see “Risk Factors—General Risk Factors—A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.” +Governance +The Company is aware of the critical nature of managing risks associated with cybersecurity threats and has established oversight mechanisms at the Board and management levels to ensure effective governance in managing risks associated with cybersecurity threats. +Board Oversight +The Board has oversight of cybersecurity risks and, specifically, the Audit Committee of the Board is charged with the oversight of the Company’s guidelines and policies to govern the process by which risk assessment and risk management are undertaken by management, including with respect to cybersecurity risks. Our Board is composed of members with diverse expertise, including risk management, technology and finance, which experience provides them with the skills needed to oversee cybersecurity risks effectively. +Management’s Role Managing Risk +The Company’s IT Committee, which includes senior executives and other members of management, meets regularly to monitor and discuss cybersecurity issues. The Senior Vice President of Information Technology, the Executive Vice President and Chief Accounting Officer (“CAO”) and the Executive Vice President, General Counsel and Head of M&A (“GC”) play a pivotal role in informing the Board on cybersecurity risks. They provide comprehensive briefings to the Board on a regular basis, with a minimum frequency of once per year. These briefings encompass a broad range of topics, including: +• current cybersecurity landscape and emerging threats; +• status of ongoing cybersecurity initiatives and strategies; +• incident reports and learnings from any cybersecurity events; and +• compliance with regulatory requirements and industry standards. +In addition to our scheduled meetings, the Board, Senior Vice President of Information Technology, CAO and GC maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive. The Board actively participates in strategic decisions related to cybersecurity, offering guidance and approval for major initiatives. This involvement ensures that cybersecurity considerations are integrated into the broader strategic objectives of the Company. +Risk Management Personnel +Primary responsibility for assessing, monitoring and managing our cybersecurity risks rests with the Senior Vice President of Information Technology . With over 35 years of experience in the information technology field, he brings a wealth of expertise to his role. His in-depth knowledge and experience are instrumental in developing and executing our cybersecurity strategies. Our Senior Vice President of Information Technology tests our compliance with standards, remediates known risks and leads our employee training program. +Reporting to the Board +The Senior Vice President of Information Technology regularly informs the Chief Executive Officer and GC of all aspects related to cybersecurity risks and incidents. This ensures that the highest levels of management are kept abreast of the +68 +Table of Contents +cybersecurity posture and potential risks facing the Company. Furthermore, significant cybersecurity matters and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues. +Monitor Cybersecurity Incidents +The Senior Vice President of Information Technology monitors the latest developments in cybersecurity, including potential threats and innovative risk management techniques. The Senior Vice President of Information Technology implements and oversees processes for the regular monitoring of our information systems. This includes the deployment of advanced security measures and regular system audits to identify potential vulnerabilities. In the event of a cybersecurity incident, the Senior Vice President of Information Technology is equipped with an incident response plan. This plan includes immediate actions to mitigate the impact and long-term strategies for remediation and prevention of future incidents. +Item 2. Properties. +See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. +Item 3. Legal Proceedings. +We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows. +Item 4. Mine Safety Disclosures. +Not applicable. +69 +Table of Contents +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +General Market Information +Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. +On February 18, 2025, we had 125,207,212 shares of common stock outstanding held by approximately 396 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. +Dividends +In each of the first, second and third quarters of 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock. In February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a quarterly cash dividend of $0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025. We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future. +Equity Compensation Plan Information +The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2024. +Equity Compensation Plan Information +Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans +Equity compensation plans approved by security holders (1)(2)(3) +1,090,557 $ 14.80 7,850,907 +Equity compensation plans not approved by security holders — — — +Total 1,090,557 $ 14.80 7,850,907 +__________________ +(1) Our Board has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). +(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report. +(3) The Matador Resources Company 2022 Employee Stock Purchase Plan (the “ESPP”) was adopted by our Board in April 2022 and approved by our shareholders on June 10, 2022. For a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report. +70 +Table of Contents +Share Performance Graph +The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2019 through December 31, 2024, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. +This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before, on, or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. +Comparison of Cumulative Total Return Among +Matador Resources Company, the Russell 2000 Index +and the Russell 2000 Energy Index +71 +Table of Contents +Repurchase of Equity by the Company or Affiliates +During the quarter ended December 31, 2024, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +Period +Total Number of Shares Purchased (1) +Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs +October 1, 2024 to October 31, 2024 41,958 $ 54.68 — — +November 1, 2024 to November 30, 2024 99 52.11 — — +December 1, 2024 to December 31, 2024 638 57.03 — — +Total +42,695 $ 54.71 — — +_________________ +(1) The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. +72 +Table of Contents +Item 6. Selected Financial Data. +Not applicable. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” +For a comparison of our results of operations for the years ended December 31, 2023 and December 31, 2022, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 27, 2024. +Overview +We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +2024 Operational Highlights +We began 2024 operating seven drilling rigs in the Delaware Basin. We added an eighth operated drilling rig in the first quarter of 2024 and a ninth operated drilling rig late in the second quarter of 2024. Upon the consummation of the Ameredev Acquisition, we continued operating a total of nine drilling rigs for the combined Matador and Ameredev properties. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2024 of $1.32 billion, which was within our estimated range for 2024 D/C/E capital expenditures of $1.15 to $1.35 billion, as provided on October 22, 2024. +During the year ended December 31, 2024, we completed and began producing oil and natural gas from 124 gross (101.9 net) operated and 127 gross (8.3 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that began producing in 2024. +Substantially all of our 2024 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Ameredev Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin, including the Ameredev Acquisition. +Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023. Our average daily oil production in 2024 was 99,808 Bbl of oil per day, an increase of 32%, as compared to 75,457 Bbl of oil per day in 2023. This increase in oil production was primarily a result of the Ameredev Acquisition and our ongoing delineation and +73 +Table of Contents +development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf per day, an increase of 26%, as compared to 338.1 MMcf per day in 2023. This increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% and 57% of our total production for the years ended December 31, 2024 and 2023, respectively. +For the year ended December 31, 2024, our oil and natural gas revenues were $3.14 billion, an increase of 24% from oil and natural gas revenues of $2.55 billion for the year ended December 31, 2023. Our oil revenues increased 29% to 2.77 billion, as compared to $2.14 billion for the year ended December 31, 2023. The increase in oil revenues resulted from the 33% increase in our oil production noted above, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. Our natural gas revenues decreased 7% to $371.5 million, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $2.38 per Mcf in 2024, as compared to $3.25 per Mcf in 2023, which was partially offset by the 26% increase in natural gas production for the year ended December 31, 2024 noted above. +We reported net income attributable to Matador shareholders of approximately $885.3 million, or $7.14 per diluted common share, on a GAAP basis for the year ended December 31, 2024, as compared to a net income of $846.1 million, or $7.05 per diluted common share, for the year ended December 31, 2023. Adjusted EBITDA for the year ended December 31, 2024 was $2.30 billion, as compared to Adjusted EBITDA of $1.85 billion for the year ended December 31, 2023. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” +At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. Our estimated total proved reserves of 611.5 million BOE at December 31, 2024 represented a 33% year-over-year increase, as compared to 460.1 million BOE at December 31, 2023. Our estimated proved oil reserves were 361.8 million Bbl at December 31, 2024, an increase of 33%, as compared to 272.3 million Bbl at December 31, 2023, and our estimated proved natural gas reserves were 1.50 Tcf at December 31, 2024, an increase of 33%, as compared to 1.13 Tcf at December 31, 2023. Proved oil reserves comprised 59% of our total proved reserves at each of December 31, 2024 and 2023. At December 31, 2024, 60% of our total proved reserves were proved developed reserves, as compared to 63% at December 31, 2023. At December 31, 2024, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. +At both December 31, 2024 and December 31, 2023, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.” +74 +Table of Contents +2024 Midstream Highlights +On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of gas gathering, water gathering and oil transportation and gathering pipeline assets. +San Mateo achieved strong operating results in 2024, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. +On December 18, 2024, we completed the Pronto Transaction, pursuant to which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million. In connection with the Pronto Transaction, the Company received a special distribution from San Mateo of approximately $219.8 million. In addition, the Company has the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by the Company and 49% by Five Point. +Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. +In connection with the Pronto Transaction, the Company dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from the Company’s operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind, an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing. +In March 2024, we completed our natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024. +During 2024, San Mateo and Pronto also closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin. +At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included: +• Natural Gas Assets : 520 MMcf per day of designed natural gas cryogenic processing capacity and approximately 295 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; +• Oil Assets : three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 110 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +75 +Table of Contents +2025 Capital Expenditure Budget +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025 and currently operate nine drilling rigs in the Delaware Basin. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2025 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2025 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells. +At December 31, 2024, we had $23.0 million in cash (excluding restricted cash) and $1.60 billion in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $2.25 billion). We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. +As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025. +76 +Table of Contents +Revenues +The following table summarizes our revenues and production data for the periods indicated. +Year Ended December 31, +2024 2023 2022 +Operating Data: +Revenues (in thousands): (1) +Oil $ 2,772,360 $ 2,144,894 $ 2,113,606 +Natural gas 371,474 400,705 792,132 +Total oil and natural gas revenues 3,143,834 2,545,599 2,905,738 +Third-party midstream services revenues 141,027 122,153 90,606 +Sales of purchased natural gas 194,097 149,869 200,355 +Realized gain (loss) on derivatives 12,724 (9,575) (157,483) +Unrealized gain (loss) on derivatives 13,299 (1,261) 18,809 +Total revenues $ 3,504,981 $ 2,806,785 $ 3,058,025 +Net Production Volumes: (1) +Oil (MBbl) 36,530 27,542 21,943 +Natural gas (Bcf) 155.8 123.4 99.3 +Total oil equivalent (MBOE) (2) +62,495 48,112 38,495 +Average daily production (BOE/d) (2) +170,751 131,813 105,465 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 75.89 $ 77.88 $ 96.32 +Oil, with realized derivatives (per Bbl) $ 75.89 $ 77.88 $ 92.87 +Natural gas, without realized derivatives (per Mcf) $ 2.38 $ 3.25 $ 7.98 +Natural gas, with realized derivatives (per Mcf) $ 2.47 $ 3.17 $ 7.15 +________________ +(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. +(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Year Ended December 31, 2024 as Compared to Year Ended December 31, 2023 +Oil and natural gas revenues . Our oil and natural gas revenues increased $598.2 million, or 24%, to $3.14 billion for the year ended December 31, 2024, as compared to $2.55 billion for the year ended December 31, 2023. Our oil revenues increased $627.5 million, or 29%, to $2.77 billion for the year ended December 31, 2024, as compared to $2.14 billion for the year ended December 31, 2023. This increase in oil revenues resulted from a 33% increase in our oil production to 36.5 million Bbl of oil for the year ended December 31, 2024, as compared to 27.5 million Bbl of oil for the year ended December 31, 2023, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. The increase in oil production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $29.2 million, or 7%, to $371.5 million for the year ended December 31, 2024, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues was primarily attributable to the 27% decrease in the weighted average natural gas price realized for the year ended December 31, 2024 to $2.38 per Mcf, as compared to $3.25 per Mcf realized for the year ended December 31, 2023, which was partially offset by a 26% increase in our natural gas production to 155.8 Bcf for the year ended December 31, 2024, as compared to 123.4 Bcf for the year ended December 31, 2023. The increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. +Third-party midstream services revenues. Our third-party midstream services revenues increased $18.9 million, or 15%, to $141.0 million for the year ended December 31, 2024, as compared to $122.2 million for the year ended December 31, 2023. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in third-party produced water disposal revenues to $56.3 million for the year ended December 31, 2024, as compared to $45.3 million for the year ended December 31, 2023 and (ii) an increase in our oil transportation revenues to $17.3 million for the year ended December 31, 2024, as compared to $11.0 million for the year ended December 31, 2023. +Sales of purchased natural gas. Our sales of purchased natural gas increased $44.2 million, or 30%, to $194.1 million for the year ended December 31, 2024, as compared to $149.9 million for the year ended December 31, 2023. This increase was primarily the result of a 45% increase in natural gas volumes sold, which was partially offset by an 11% decrease in natural gas +77 +Table of Contents +prices realized. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income. +Realized gain (loss) on derivatives . Our realized net gain on derivatives was $12.7 million for the year ended December 31, 2024, as compared to a realized net loss of approximately $9.6 million for the year ended December 31, 2023. We realized a net gain of approximately $12.7 million related to our natural gas basis differential swap contracts for the year ended December 31, 2024, resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average gain on our natural gas derivatives of approximately $0.09 per Mcf of natural gas produced during the year ended December 31, 2024, as compared to an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023. +Unrealized gain (loss) on derivatives . Our unrealized gain on derivatives was approximately $13.3 million for the year ended December 31, 2024, as compared to an unrealized loss of $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swap contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023. +78 +Table of Contents +Expenses +The following table summarizes our operating expenses and other income (expense) for the periods indicated. +Year Ended December 31, +2024 2023 2022 +(In thousands, except expenses per BOE) +Expenses: +Production taxes, transportation and processing $ 306,751 $ 264,493 $ 282,193 +Lease operating 341,544 243,655 157,105 +Plant and other midstream services operating 171,492 128,910 95,522 +Purchased natural gas 142,715 129,401 178,937 +Depletion, depreciation and amortization 974,300 716,688 466,348 +Accretion of asset retirement obligations 6,027 3,943 2,421 +General and administrative 127,454 110,373 116,229 +Total expenses 2,070,283 1,597,463 1,298,755 +Operating income 1,434,698 1,209,322 1,759,270 +Other income (expense): +Net loss on asset sales and impairment — (202) (1,311) +Interest expense (171,687) (121,520) (67,164) +Other income (expense) 696 8,785 (5,121) +Total other expense (170,991) (112,937) (73,596) +Income before income taxes 1,263,707 1,096,385 1,685,674 +Income tax provision (benefit) +Current 27,059 13,922 54,877 +Deferred 265,305 172,104 344,480 +Total income tax provision 292,364 186,026 399,357 +Net income attributable to non-controlling interest in subsidiaries (86,021) (64,285) (72,111) +Net income attributable to Matador Resources Company shareholders $ 885,322 $ 846,074 $ 1,214,206 +Expenses per BOE: +Production taxes, transportation and processing $ 4.91 $ 5.50 $ 7.33 +Lease operating $ 5.47 $ 5.06 $ 4.08 +Plant and other midstream services operating $ 2.74 $ 2.68 $ 2.48 +Depletion, depreciation and amortization $ 15.59 $ 14.90 $ 12.11 +General and administrative $ 2.04 $ 2.29 $ 3.02 +Year Ended December 31, 2024 as Compared to Year Ended December 31, 2023 +Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $42.3 million, or 16%, to $306.8 million for the year ended December 31, 2024, as compared to $264.5 million for the year ended December 31, 2023. This increase was primarily attributable to the $43.4 million increase in our production taxes to $243.6 million for the year ended December 31, 2024, as compared to $200.2 million for the year ended December 31, 2023, primarily due to the $598.2 million increase in oil and natural gas revenues for the year ended December 31, 2024, as compared to the year ended December 31, 2023. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 11% to $4.91 per BOE for the year ended December 31, 2024, as compared to $5.50 per BOE for the year ended December 31, 2023. This decrease was primarily attributable to a decrease in transportation and processing expense per BOE that resulted from a mix of revenue contracts, including from San Mateo, between the two periods. +Lease operating expenses. Our lease operating expenses increased $97.9 million, or 40%, to $341.5 million for the year ended December 31, 2024, as compared to $243.7 million for the year ended December 31, 2023. On a unit-of-production basis, our lease operating expenses increased 8% to $5.47 per BOE for the year ended December 31, 2024, as compared to $5.06 per BOE for the year ended December 31, 2023. These increases for the year ended December 31, 2024 were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year ended December 31, 2024, as compared to the year ended December 31, 2023. +Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $42.6 million, or 33%, to $171.5 million for the year ended December 31, 2024, as compared to $128.9 million for the year ended December 31, 2023. This increase was primarily attributable to increased throughput volumes at San Mateo from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations, +79 +Table of Contents +including assets acquired in the Ameredev Acquisition, of $73.9 million for the year ended December 31, 2024, as compared to $41.4 million for the year ended December 31, 2023 and (ii) increased expenses associated with our commercial produced water disposal operations of $63.0 million for the year ended December 31, 2024, as compared to $53.6 million for the year ended December 31, 2023. +Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $257.6 million, or 36%, to $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition and a 30% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 5% to $15.59 per BOE for the year ended December 31, 2024, as compared to $14.90 per BOE for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition. +General and administrative. Our general and administrative expenses increased $17.1 million, or 15%, to $127.5 million for the year ended December 31, 2024, as compared to $110.4 million for the year ended December 31, 2023, primarily due to +increased compensation expenses for our existing employees as well as the addition of new employees to support the continued +growth in our land, geoscience, drilling, completion, production, midstream and administration functions. Our general and administrative expenses on a unit-of-production basis decreased 11% to $2.04 per BOE for the year ended December 31, 2024, as compared to $2.29 per BOE for the year ended December 31, 2023, primarily as a result of the 30% increase in our total oil equivalent production between the two periods. +Interest expense. For the year ended December 31, 2024, we incurred total interest expense of approximately $201.5 million. We capitalized approximately $29.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2024 and expensed the remaining $171.7 million to operations. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. The increase in interest expense for the year ended December 31, 2024 was primarily attributable to an increase in our average debt outstanding between the two periods. In April 2024, we completed the 2026 Notes Repurchase and the 2032 Notes Offering and in September 2024 we completed the 2033 Notes Offering, resulting in a net increase in our total senior notes outstanding to $2.15 billion at December 31, 2024 as compared to $1.20 billion at December 31, 2023. In connection with the 2026 Notes Repurchase, the amendment of our Credit Agreement in March 2024 and the amendment of the San Mateo Credit Facility in November 2024, we also incurred a loss of approximately $6.2 million included in interest expense for the year ended December 31, 2024. +Total income tax provision. We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. +Liquidity and Capital Resources +Our primary use of capital has been, and we expect will continue during 2025 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. +At December 31, 2024, we had cash totaling $23.0 million and restricted cash totaling $71.7 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +At December 31, 2024, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 2032 Notes, (iii) $750.0 million of outstanding 2033 Notes, (iv) $595.5 million of borrowings +80 +Table of Contents +outstanding under the Credit Agreement and (v) approximately $52.9 million in outstanding letters of credit issued pursuant to the Credit Agreement. +On March 22, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.50 billion, (ii) increase the elected borrowing commitment from $1.325 billion to $1.50 billion, (iii) increase the maximum facility amount from $2.00 billion to $3.50 billion, (iv) extend the maturity date from October 31, 2026 to March 22, 2029, (v) appoint PNC Bank, National Association as administrative agent thereunder and (vi) add five new banks to the lending group. This March 2024 redetermination constituted the regularly scheduled May 1 redetermination. +On March 28, 2024, we completed the 2024 Equity Offering and used the net proceeds for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement. +On April 2, 2024, we completed the 2032 Notes Offering and used the net proceeds to fund the 2026 Notes Repurchase and for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement. +On September 18, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) provide for a term loan of $250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitment from $1.50 billion to $2.25 billion. +On September 25, 2024, we completed the 2033 Notes Offering and used the net proceeds to partially repay borrowings outstanding under the Credit Agreement including all of the $250.0 million in outstanding borrowings under the term loan. +On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. During the fourth quarter of 2024, we received $113.6 million from the sale of Piñon resulting from our approximate 19% interest in the parent company of Piñon that we acquired as part of the Ameredev Acquisition and used these proceeds to reduce borrowings under our Credit Agreement. We currently expect to receive an additional $4.8 million from the sale of Piñon in the first half of 2025. +On November 21, 2024, we received notice from PNC Bank, National Association, as administrative agent under the Credit Agreement, that the lenders under the Credit Agreement completed their scheduled semi-annual review of our proved oil and natural gas reserves and unanimously determined to increase the borrowing base from $2.50 billion to $3.25 billion. We chose to maintain the elected borrowing commitments at $2.25 billion. +The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024. +At December 31, 2024, San Mateo had $615.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. On November 26, 2024, San Mateo and its lenders entered into an amendment to the San Mateo Credit Facility to, among other things: (i) extend the maturity date of the facility from December 9, 2026 to November 26, 2029, (ii) increase the lender commitments from $535.0 million to $800.0 million and (iii) add six new banks to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.05 billion. +The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024. +In February 2024, April 2024 and July 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock. In February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a +81 +Table of Contents +quarterly cash dividend of $0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025. +We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025. We currently operate nine drilling rigs in the Delaware Basin. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2025 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2025 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells. +As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025. +Our 2025 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. +Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2025 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin. Our existing operated and non-operated wells may not produce at the levels we are forecasting or may be temporarily shut in or restricted due to low commodity prices, and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2025 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +82 +Table of Contents +Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below. +Year Ended December 31, +2024 2023 2022 +(In thousands) +Net cash provided by operating activities $ 2,246,885 $ 1,867,828 $ 1,978,739 +Net cash used in investing activities (3,672,114) (3,211,192) (1,037,477) +Net cash provided by (used in) financing activities 1,413,673 902,332 (480,852) +Net change in cash $ (11,556) $ (441,032) $ 460,410 +Adjusted EBITDA attributable to Matador Resources Company shareholders (1) +$ 2,298,777 $ 1,849,547 $ 2,127,156 +__________________ +(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. +Net Cash Provided by Operating Activities +Net cash provided by operating activities increased by $379.1 million to $2.25 billion for the year ended December 31, 2024, as compared to net cash provided by operating activities of $1.87 billion for the year ended December 31, 2023. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.23 billion for the year ended December 31, 2024 from $1.82 billion for the year ended December 31, 2023. This increase was primarily attributable to the 30% increase in total oil equivalent production during 2024, as compared to 2023, which was partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023. Changes in our operating assets and liabilities between December 31, 2023 and December 31, 2024 resulted in a net decrease of approximately $36.9 million in net cash provided by operating activities for the year ended December 31, 2024, as compared to the year ended December 31, 2023. +Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +Net Cash Used in Investing Activities +Net cash used in investing activities increased by $460.9 million to $3.67 billion for the year ended December 31, 2024 from $3.21 billion for the year ended December 31, 2023. This increase in net cash used in investing activities was primarily due to (i) expenditures related to the Ameredev Acquisition of $1.83 billion in 2024, which was $155.1 million higher than expenditures related to the Advance Acquisition of $1.68 billion in 2023, (ii) an increase between the periods of $266.8 million in acquisitions of oil and natural gas properties, (iii) an increase between the periods of $118.2 million in midstream capital expenditures and (iv) an increase of $30.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin. These increases were partially offset by proceeds from the sale of our equity method investment in Piñon of $113.6 million for the year ended December 31, 2024. +Net Cash Provided by (Used in) Financing Activities +Net cash provided by financing activities increased $511.3 million to $1.41 billion for the year ended December 31, 2024, from net cash provided by financing activities of $902.3 million for the year ended December 31, 2023. During the year ended December 31, 2024, our net cash provided by financing activities was primarily attributable to (i) proceeds from the 2032 Notes Offering of $900.0 million, (ii) proceeds from the 2033 Notes Offering of $750.0 million, (iii) proceeds from the 2024 Equity Offering of $344.7 million, (iv) net contributions to San Mateo of $116.9 million, which included a contribution of $171.5 million from Five Point to San Mateo related to the Pronto Transaction, (v) net borrowings under the Credit Agreement of $95.5 million and (vi) net borrowings under the San Mateo Credit Facility of $93.0 million. These increases were partially offset by (i) the repurchase of an aggregate principal amount of approximately $699.2 million of 2026 Notes in the 2026 Notes Repurchase, (ii) dividends paid of $104.9 million, (iii) costs associated with the 2032 Notes Offering and 2033 Notes Offering of $28.2 million, (iv) costs to amend the Credit Agreement and the San Mateo Credit Facility of $33.4 million and (v) payment of taxes related to stock-based compensation of $17.0 million. During the year ended December 31, 2023, our net cash provided +83 +Table of Contents +by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million. +See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2028 Notes, the 2032 Notes and the 2033 Notes. +Non-GAAP Financial Measures +We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. +Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. +Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. +The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively. +Year Ended December 31, +2024 2023 2022 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Income: +Net income attributable to Matador Resources Company shareholders $ 885,322 $ 846,074 $ 1,214,206 +Net income attributable to non-controlling interest in subsidiaries 86,021 64,285 72,111 +Net income 971,343 910,359 1,286,317 +Interest expense 171,687 121,520 67,164 +Total income tax provision 292,364 186,026 399,357 +Depletion, depreciation and amortization 974,300 716,688 466,348 +Accretion of asset retirement obligations 6,027 3,943 2,421 +Unrealized (gain) loss on derivatives (13,299) 1,261 (18,809) +Non-cash stock-based compensation expense 14,982 13,661 15,123 +Net loss on impairment — 202 1,311 +Expense (income) related to contingent consideration and other 5,420 (6,038) 4,926 +Consolidated Adjusted EBITDA 2,422,824 1,947,622 2,224,158 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (124,047) (98,075) (97,002) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 2,298,777 $ 1,849,547 $ 2,127,156 +84 +Table of Contents +Year Ended December 31, +2024 2023 2022 +(In thousands) +Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities: +Net cash provided by operating activities $ 2,246,885 $ 1,867,828 $ 1,978,739 +Net change in operating assets and liabilities (13,080) (50,027) 117,935 +Interest expense, net of non-cash portion 155,154 114,473 63,064 +Current income tax provision 27,059 13,922 54,877 +Other non-cash and non-recurring expense 6,806 1,426 9,543 +Adjusted EBITDA attributable to non-controlling interest in subsidiaries (124,047) (98,075) (97,002) +Adjusted EBITDA attributable to Matador Resources Company shareholders $ 2,298,777 $ 1,849,547 $ 2,127,156 +For the year ended December 31, 2024, we reported net income attributable to Matador shareholders of $885.3 million, as compared to $846.1 million for the year ended December 31, 2023. This increase primarily resulted from significantly higher oil and natural gas production for the year ended December 31, 2024, as compared to the year ended December 31, 2023. These increases were partially offset by increased depletion, depreciation and amortization expenses of $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, increased interest expense of $171.7 million for the year ended December 31, 2024, as compared to $121.5 million for the year ended December 31, 2023, an increased income tax provision of $292.4 million for the year ended December 31, 2024, as compared to an income tax provision of $186.0 million for the year ended December 31, 2023 and by lower realized oil and natural gas prices between the periods. +Adjusted EBITDA, a non-GAAP financial measure, increased $449.2 million to $2.30 billion for the year ended December 31, 2024, as compared to $1.85 billion for the year ended December 31, 2023. This increase was primarily attributable to higher oil and natural gas production noted above, partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023. +Off-Balance Sheet Arrangements +From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. +85 +Table of Contents +Obligations and Commitments +We had the following material contractual obligations and commitments at December 31, 2024. +Payments Due by Period +Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years +(In thousands) +Contractual Obligations: +Borrowings, including letters of credit (1) +$ 1,272,408 $ — $ — $ 1,272,408 $ — +Senior unsecured notes (2) +2,150,000 — — 500,000 1,650,000 +Office leases 91,759 1,474 8,913 11,269 70,103 +Non-operated drilling commitments (3) +60,783 60,783 — — — +Drilling rig contracts (4) +20,425 20,425 — — — +Asset retirement obligations (5) +122,668 8,431 1,726 1,912 110,599 +Transportation, gathering, processing and disposal agreements with non-affiliates (6) +692,598 101,029 206,093 161,056 224,420 +Transportation, gathering, processing and disposal agreements with San Mateo (7) +804,305 3,585 227,433 165,272 408,015 +Midstream contracts (8) +67,662 67,662 — — — +Total contractual cash obligations $ 5,282,608 $ 263,389 $ 444,165 $ 2,111,917 $ 2,463,137 +__________________ +(1) The amounts included in the table above represent principal maturities only. At December 31, 2024, we had $595.5 million in borrowings outstanding under the Credit Agreement and approximately $52.9 million in outstanding letters of credit issued pursuant to the Credit Agreement. The outstanding borrowings under the Credit Agreement mature on March 22, 2029. At December 31, 2024 San Mateo had $615.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029. Assuming the amounts outstanding and interest rates of 6.19% and 6.44%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2024, the interest expense for such facilities is expected to be approximately $37.4 million and $40.2 million, respectively, each year until maturity. +(2) The amounts included in the table above represent principal maturities only. Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2024 is expected to be approximately $34.4 million each year until maturity. Interest expense on the $900.0 million of outstanding 2032 Notes as of December 31, 2024 is expected to be approximately $58.5 million each year until maturity. Interest expense on the $750.0 million of outstanding 2033 Notes as of December 31, 2024 is expected to be approximately $46.9 million each year until maturity. +(3) At December 31, 2024, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. +(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(5) The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2024. +(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments, including certain agreements with Northwind that were entered into in connection with the Pronto Transaction. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments. +(7) We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. In connection with the Pronto Transaction, we dedicated to Pronto our current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements with Pronto whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. +(8) At December 31, 2024, we had outstanding commitments related to the construction and installation of San Mateo’s Marlan Processing Plant expansion with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase compressors to be utilized in San Mateo operations. +86 +Table of Contents +General Outlook and Trends +Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. For example, the recent election of President Trump and a Republican-controlled Congress may alter our current regulatory framework and impact our business and the oil and gas industry generally. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, ongoing military conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, political instability, particularly in China and in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, oil and natural gas price differentials and other factors. +The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +For the year ended December 31, 2024, oil prices averaged $75.76 per Bbl, as compared to $77.60 per Bbl in 2023, ranging from a high of $86.91 per Bbl in early April to a low of $65.75 per Bbl in mid-September, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $75.89 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2024, as compared to $77.88 per Bbl (with no realized gains or losses from oil derivatives) for the year ended December 31, 2023. At February 18, 2025, the WTI oil futures contract price for the earliest delivery date had increased slightly from year-end 2024, closing at $71.85 per Bbl, but was lower compared to $79.19 per Bbl on February 16, 2024. +For the year ended December 31, 2024, natural gas prices averaged $2.40 per MMBtu, as compared to $2.66 per MMBtu in 2023, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2024, natural gas prices ranged from a low of $1.58 per MMBtu in late March to a high of $3.95 per MMBtu in late December. As a result of expected winter weather, increased demand for LNG exports, tightening storage levels and concerns about potential supply disruptions, natural gas prices increased over the course of the fourth quarter of 2024, finishing the year at $3.63 per MMBtu. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were also lower in 2024 as compared to 2023, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2024. We realized a weighted average natural gas price of $2.38 per Mcf ($2.47 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2024, as compared to $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2023. At February 18, 2025, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from year-end 2024, closing at $4.01 per MMBtu, and was higher as compared to $1.61 per MMBtu at February 16, 2024. +The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2024, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas. +The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 18, 2025, this oil price differential was approximately +$1.33 per Bbl. At February 18, 2025, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2025. +Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($2.20) per MMBtu for the year ended December 31, 2024. Between December 31, 2024 and February 18, 2025, this natural gas price differential widened to approximately ($2.70) per MMBtu. A significant portion of our +87 +Table of Contents +Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2023 and 2024, we typically realized a narrower differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 5% of our reported natural gas production for the year ended December 31, 2024 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. +From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During the year ended December 31, 2024, we realized gains on our natural gas basis differential derivative contracts of approximately $12.7 million resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. At December 31, 2024, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in 2025. +We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any material interruptions with produced water disposal, takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. +We have at times experienced inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices remain at their current levels or increase, we may be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows. +We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. At February 18, 2025, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2025 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2025. We could be subject to the CAMT in future years, which would require us to pay minimum cash tax payments of 15% of annual adjusted pretax book income. +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For more information about the Company’s regulatory matters, see “Business—Regulation” and “Risk Factors—Risks Related to Laws and Regulations”. +Certain segments of the investor community have at times expressed negative sentiment towards investing in the oil and natural gas industry and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. See “Risk Factors—Risks Related to our Common Stock—Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price.” +Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production +88 +Table of Contents +declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth”. +We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2024. +Oil and Natural Gas Properties +We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. +89 +Table of Contents +Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue +Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. +Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including assumptions related to oil and natural gas prices, development expenditures, operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” +Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. +Income Taxes +We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. +We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. +Purchase Accounting +Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023 and the Ameredev Acquisition in 2024. +90 +Table of Contents +In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition and the Ameredev Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts. The most significant assumptions relate to the estimated fair values of oil and natural gas properties. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of future production volumes, estimates of future commodity prices, expected development and operating costs, an estimate of a market-based weighted average cost of capital rate and recent market comparable transactions for unproved acreage. +Recent Accounting Pronouncements +See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. +Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production. +We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option or options have different fixed price components. When the settlement price is below the price floor established by the collar, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil, natural gas or NGL volume. When the settlement price is above the price ceiling established by the costless collar, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil, natural gas or NGL volume. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. +We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2024, Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof) were the counterparties for our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. +At December 31, 2024, we had various costless collar contracts open and in place to mitigate our exposure to oil price volatility, each with an established price floor and ceiling. At December 31, 2024, we had natural gas basis differential swap contracts open and in place to mitigate our exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. We had no open contracts associated with NGL prices at December 31, 2024. +See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. Such information is incorporated herein by reference. +Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative +91 +Table of Contents +arrangements in the future. See “Risk Factors—Risks Related to Laws and Regulations—Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.” +Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt. At December 31, 2024, we had $595.5 million of outstanding borrowings under our Credit Agreement at an interest rate of 6.19%, $500.0 million of outstanding 2028 Notes at a coupon rate of 6.875%, $900.0 million of outstanding 2032 Notes at a coupon rate of 6.500%, $750.0 million of outstanding 2033 Notes at a coupon rate of 6.250% and $615.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 6.44%. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. +Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo is subject to the credit risk of their customers. The inability or failure of our or San Mateo’s significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. +While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 18, 2025 were Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof), which are all lenders under our Credit Agreement. +Impact of inflation . Inflation in the United States has become much more significant in recent years. We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward. We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors—Risks Related to our Financial Condition—Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected” and “Risk Factors—Risks Related to our Operations—The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.” +Item 8. Financial Statements and Supplementary Data. +Our financial statements appear at the end of this Annual Report beginning on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2024 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and +92 +Table of Contents +communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2024, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2024 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2025 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 25, 2025 +94 +Table of Contents +Item 9B. Other Information. +During the three months ended December 31, 2024, no director or officer (as defined in Rule 16a-1(f) under the Exchange Act) of the Company adopted , modified or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2025 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.” +Item 11. Executive Compensation. +The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.” +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.” +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” +Item 14. Principal Accounting Fees and Services. +The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 3—Ratification of Appointment of KPMG LLP.” +95 +Table of Contents +PART IV +Item 15. Exhibits and Financial Statement Schedules. +The following documents are filed as part of this Annual Report: +1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2024 and 2023, Consolidated Statements of Income for the Years Ended December 31, 2024, 2023 and 2022, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2024, 2023 and 2022 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022. +2. Financial Statement Schedules : All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto. +3. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below. +Item 16. Form 10-K Summary. +None. +96 +Table of Contents +EXHIBIT INDEX +Exhibit +Number Description +2.1* +Securities Purchase Agreement, dated January 24, 2023, by and among MRC Hat Mesa, LLC, MRC Energy Company (solely for the limited purposes stated therein), AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 24, 2023). +2.2 +Amendment No. 1 to Securities Purchase Agreement, dated April 5, 2023, by and among MRC Hat Mesa, LLC, AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC ( incorporated by reference to Exhibit 2.2 to the Annual Report on Form 10-K for the year ended December 31, 202 3 ). +2.3* +Waiver and Release Agreement and Amendment No. 2 to Securities Purchase Agreement, dated December 1, 2023, by and among MRC Hat Mesa, LLC, AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC ( incorporated by reference to Exhibit 2.3 to the Annual Report on Form 10-K for the year ended December 31, 202 3 . ). +2.4* +Securities Purchase Agreement, dated June 12, 2024, by and among MRC Toro, LLC, MRC Energy Company (solely for the limited purposes stated therein), Ameredev II Parent, LLC, Ameredev Intermediate II, LLC and Ameredev Stateline II, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on June 12, 2024). +2.5* +Amendment No. 1 to Securities Purchase Agreement, dated August 29, 2024, by and among MRC Toro, LLC, Ameredev II Parent, LLC, Ameredev Intermediate II, LLC and Ameredev Stateline II, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2024). +2.6 +Amendment No. 2 to Securities Purchase Agreement, dated February 14, 2025, by and among MRC Toro, LLC, Ameredev II Parent, LLC, Ameredev Intermediate II, LLC (filed herewith). +3.1 +Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.2 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.3 +Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +3.4 +Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018). +4.1 +Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012). +4.2 +Indenture, dated as of April 11, 2023, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 11, 2023). +4.3 +First Supplemental Indenture, dated as of July 25, 2023, by and among Matador Resources Company, MRC Hat Mesa, LLC, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2023). +4.4 +Indenture, dated as of April 2, 2024, by and among Matador Resources Company, the subsidiary guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 2, 2024). +4.5 +First Supplemental Indenture, dated as of September 20, 2024, by and among MRC Toro, LLC, the subsidiary guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2024). +4.6 +Second Supplemental Indenture, dated as of September 20, 2024, by and among MRC Toro, LLC, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2024). +97 +Table of Contents +4.7 +Indenture, dated as of September 25, 2024, by and among Matador Resources Company, the subsidiary guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on September 25, 2024). +4.8 +Description of Capital Stock (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2019). +10.1† +Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.2† +First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.3† +Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011). +10.4† +Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014). +10.5† +Form of Employment Agreement between Matador Resources Company and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). +10.6† +First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.7† +Form of Employment Agreement between Matador Resources Company and Michael D. Frenzel (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 3 0, 2022). +10.8† +Form of Employment Agreement between Matador Resources Company and each of Brian J. Willey, Christopher P. Calvert, W. Thomas Elsener, Bryan A. Erman and Glenn W. Stetson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2024). +10.9† +Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011). +10.10 +Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.11 +Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). +10.12 +Fourth Amended and Restated Credit Agreement, dated as of November 18, 2021, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 18, 2021). +10.13 +First Amendment to Fourth Amended and Restated Credit Agreement dated as of April 25, 2022, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2022). +10.14 +Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 31, 2023, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, Royal Bank of Canada, as resigning Administrative Agent, and Truist Bank, as successor Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 3, 2023). +98 +Table of Contents +10.15 +Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of April 10, 2023, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Truist Bank, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2023). +10.16 +Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 19, 2023, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and Truist Bank, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 19, 2023). +10.17 +Fifth Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 22, 2024, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and PNC Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 25, 2024). +10.18 +Sixth Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 18, 2024, by and among MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and PNC Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 19, 2024). +10.19† +Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.20† +Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.21† +Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015). +10.22† +Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.23† +Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.24† +Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015). +10.25† +Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016). +10.26† +Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017). +10.27† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.28† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.29† +Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.30† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +10.31† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017). +99 +Table of Contents +10.32† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.33† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018). +10.34† +Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019). +10.35† +First Amendment to Matador Resources Company 2019 Long-Term Incentive Plan effective April 21, 2022 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 16, 2022). +10.36† +Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.37† +Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019). +10.38† +Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.39† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020). +10.40† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.58 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.41† +Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.42† +Form of Restricted Stock Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan with ratable vesting for employees without employment agreements (incorporated by reference to Exhibit 10.60 to the Annual Report on Form 10-K for the year ended December 31, 2021). +10.43† +Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the year ended December 31, 2020). +10.44† +Matador Resources Company 2022 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 16, 2022). +19.1 +Matador Resources Company Insider Trading Policy (filed herewith). +21.1 +List of Subsidiaries of Matador Resources Company (filed herewith). +23.1 +Consent of KPMG LLP (filed herewith). +23.2 +Consent of Netherland, Sewell & Associates, Inc . (filed herewith). +31.1 +Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +31.2 +Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). +32.1 +Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). +97 +Matador Resources Company Clawback Policy ( incorporated by reference to Exhibit 97 to the Annual Report on Form 10-K for t he year ended December 31, 2023 ). +100 +Table of Contents +99.1 +Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). +101 +The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2024, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). +104 Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101). +† Indicates a management contract or compensatory plan or arrangement. +* This filing excludes certain schedules and exhibits pursuant to Item 601(a)(5) of Regulation S-K, which the Company agrees to furnish supplementally to the SEC upon request; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished. +101 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. +MATADOR RESOURCES COMPANY +February 25, 2025 By: /s/ Joseph Wm. Foran +Joseph Wm. Foran +Chairman and Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature Title Date +/s/ Joseph Wm. Foran Chairman and Chief Executive Officer February 25, 2025 +Joseph Wm. Foran (Principal Executive Officer) +/s/ Brian J. Willey Executive Vice President and Chief Financial Officer February 25, 2025 +Brian J. Willey (Principal Financial Officer) +/s/ Robert T. Macalik Executive Vice President and Chief Accounting Officer February 25, 2025 +Robert T. Macalik (Principal Accounting Officer) +/s/ Shelley F. Appel Director February 25, 2025 +Shelley F. Appel +/s/ Reynald A. Baribault Director February 25, 2025 +Reynald A. Baribault +/s/ R. Gaines Baty Director February 25, 2025 +R. Gaines Baty +/s/ William M. Byerley Director February 25, 2025 +William M. Byerley +/s/ Monika U. Ehrman Director February 25, 2025 +Monika U. Ehrman +/s/ Paul W. Harvey Director February 25, 2025 +Paul W. Harvey +/s/ James M. Howard Director February 25, 2025 +James M. Howard +/s/ Timothy E. Parker Director February 25, 2025 +Timothy E. Parker +/s/ Kenneth L. Stewart Director February 25, 2025 +Kenneth L. Stewart +/s/ Susan M. Ward Director February 25, 2025 +Susan M. Ward +102 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report. +Batch drilling . The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled. +Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water. +Bcf . One billion cubic feet of natural gas. +Bench . A geologic zone or formation or a subdivision of a geologic formation. +BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas. +BOE/d . BOE per day. +Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. +Central delivery point or CDP . The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point. +Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. +Condensate . A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. +Conventional reservoirs or resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. +Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. +Developed acreage . The number of acres that are allocated or assignable to productive wells. +Developed oil and natural gas reserves . Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. +Development well . A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differential . The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price. +Dry hole . A well found to be incapable of producing hydrocarbons. +Economically producible . As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. +ESP . Electric submersible pump. +Exploratory well . A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well. +Extension well . A well drilled to extend the limits of a known reservoir. +Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the +103 +Table of Contents +assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” +Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. +GAAP, or U.S. GAAP . United States, generally accepted accounting principles. +Gross acres or gross wells . The total acres or wells in which a working interest is owned. +Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. +Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. +Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. +Lateral length . Length of the drilled or completed portion of a horizontal well. +Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. +MBbl . One thousand barrels of crude oil, other liquid hydrocarbons or produced water. +MBOE . One thousand BOE. +Mcf . One thousand cubic feet of natural gas. +MMBtu . One million British thermal units. +MMcf . One million cubic feet of natural gas. +NGL . Natural gas liquids. +Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. +Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. +NYMEX . New York Mercantile Exchange. +Organization of Petroleum Exporting Countries or OPEC . An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid. +OPEC+ . A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia. +Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. +Pad . The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well. +Pad drilling . The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated. +Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. +104 +Table of Contents +Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. +Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. +Possible reserves . Additional reserves that are less certain to be recovered than probable reserves. +Probable reserves . Additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. +Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. +Production costs . Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining such wells and related equipment and facilities. +Properties . Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests. +Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. +Prospectivity . Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation. +Proved area . The part of a property to which proved reserves have been specifically attributed. +Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves. +Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. +Proved properties . Properties with proved reserves. +Proved reserves . The quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Reasonable certainty. A high degree of confidence that the quantities of oil and/or natural gas will be recovered. +Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. +Repeatability . The potential ability to drill multiple wells within a prospect or trend. +Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. +Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. +Royalty interest . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +105 +Table of Contents +2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile. +3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. +Service well. A well drilled or completed for the purpose of supporting production in an existing field. +Simul-Frac (Simultaneous Fracturing). Simul-Frac is a hydraulic fracturing technique in which two wells are fractured simultaneously using one hydraulic fracturing fleet. This differs from traditional zipper-frac where only one well is hydraulically stimulated. +Spud . The act of beginning to drill an oil or natural gas well. +Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to specific geologic condition. +Tcf . One trillion cubic feet of natural gas. +Throughput . The volume of product transported or passing through a pipeline, plant or other facility. +Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. +Trimul-Frac (Triple Simultaneous Fracturing). Trimul-Frac is an advanced hydraulic fracturing technique where three wells are fractured simultaneously using one hydraulic fracturing fleet. While similar to Simul-Frac in terms of treating multiple wells simultaneously, Trimul-Frac stimulates three wells versus two. +Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. +Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. +Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned. +Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. +Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. +Volumetric reserves analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. +WTI . West Texas Intermediate. +Wellbore . The hole made by a well. +Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. +106 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2024, 2023 and 2022 +Index +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Financial Statements +Consolidated Balance Sheets as of December 31, 2024 and 2023 +F-5 +Consolidated Statements of Income for the Years Ended December 31, 2024, 2023 and 2022 +F-6 +Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2024, 2023 and 2022 +F-7 +Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022 +F- 8 +Notes to Consolidated Financial Statements +F- 9 +Unaudited Supplementary Information +F- 46 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2025 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation +As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. +F-2 +Table of Contents +For the year ended December 31, 2024, the Company recorded depletion expense of evaluated oil and natural gas properties of $925.6 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company’s consolidated balance sheet includes $12.5 billion of gross evaluated oil and natural gas properties as of December 31, 2024. The Company’s internal reservoir engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reservoir engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company. +We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to future production volumes, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reservoir engineers as well as the external reservoir engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reservoir engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reservoir engineers’ estimate regarding future operating and development costs based on historical actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserves estimates. We recalculated the depletion expense calculation and analyzed it for compliance with industry and regulatory standards. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results. +Fair value measurement of evaluated oil and natural gas properties acquired in the Ameredev business combination +As discussed in Note 2 and Note 6 to the consolidated financial statements, on September 18, 2024, the Company completed the acquisition of Ameredev Stateline II, LLC. As a result of the transaction, the Company acquired evaluated oil and natural gas properties with an acquisition-date fair value of $1.83 billion. The acquisition was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed at their estimated fair values as of the acquisition date, with any excess purchase price allocated to goodwill. The fair value of evaluated oil and natural gas properties were measured using the discounted cash flow method. Significant inputs to the valuation of evaluated oil and natural gas properties included estimates of future production volumes and future commodity prices. The Company’s internal reservoir engineers estimated evaluated future production volumes and the Company engages a third-party reservoir engineering firm to perform an independent assessment. +We identified the evaluation of the fair value measurement of the evaluated oil and natural gas properties acquired in the Ameredev business combination as a critical audit matter. Subjective auditor judgment was required to evaluate future production volumes and future commodity prices used to estimate the fair value of such properties as changes to these assumptions could have had a significant impact on the determination of the fair value. Additionally, the audit effort associated with evaluating the future commodity prices required specialized skills and knowledge. +The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s acquisition-date valuation process, including controls over the determination of the assumptions, as listed above, used to measure the initial fair value of the acquired evaluated oil and natural gas properties. We evaluated (1) the professional qualifications of the Company’s internal and external reservoir engineers and the external engineering firm, (2) the knowledge, skills, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We assessed compliance of the methodology used by the Company’s internal and external reservoir engineers to estimate future production volumes with industry and regulatory standards. We compared the historical production volumes of Ameredev used to estimate future production volumes to production volumes reported to third parties. We also compared the estimated future evaluated production +F-3 +Table of Contents +volumes used by the Company to historical Ameredev production volumes and to the future production assumptions made on the Company’s comparable assets. We tested the relevant basis differentials that were applied to the future commodity price assumptions by comparing to historical realized basis differentials from both Ameredev and the Company. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the future commodity price assumptions by comparing to an independently developed range of forward price estimates from analysts and other industry sources. +/s/ KPMG LLP +We have served as the Company’s auditor since 2014. +Dallas, Texas +February 25, 2025 +F-4 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED BALANCE SHEETS +(In thousands, except par value and share data) +December 31, +2024 2023 +ASSETS +Current assets +Cash $ 23,033 $ 52,662 +Restricted cash 71,709 53,636 +Accounts receivable +Oil and natural gas revenues 331,590 274,192 +Joint interest billings 260,555 163,660 +Other 62,584 35,102 +Derivative instruments 15,968 2,112 +Lease and well equipment inventory 38,469 41,808 +Prepaid expenses and other current assets 123,437 92,700 +Total current assets 927,345 715,872 +Property and equipment, at cost +Oil and natural gas properties, full-cost method +Evaluated 12,534,290 9,633,757 +Unproved and unevaluated 1,702,203 1,193,257 +Midstream properties 1,683,334 1,318,015 +Other property and equipment 47,532 40,375 +Less accumulated depletion, depreciation and amortization ( 6,203,263 ) ( 5,228,963 ) +Net property and equipment 9,764,096 6,956,441 +Other assets +Derivative instruments — 558 +Other long-term assets 158,668 54,125 +Total other assets 158,668 54,683 +Total assets $ 10,850,109 $ 7,726,996 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Current liabilities +Accounts payable $ 147,139 $ 68,185 +Accrued liabilities 441,484 365,848 +Royalties payable 227,865 161,983 +Amounts due to affiliates 30,544 28,688 +Advances from joint interest owners 83,338 19,954 +Other current liabilities 64,987 40,617 +Total current liabilities 995,357 685,275 +Long-term liabilities +Borrowings under Credit Agreement 595,500 500,000 +Borrowings under San Mateo Credit Facility 615,000 522,000 +Senior unsecured notes payable 2,114,908 1,184,627 +Asset retirement obligations 114,237 87,485 +Deferred income taxes 847,666 581,439 +Other long-term liabilities 110,009 38,482 +Total long-term liabilities 4,397,320 2,914,033 +Commitments and contingencies (Note 14) +Shareholders’ equity +Common stock — $ 0.01 par value, 160,000,000 shares authorized; 125,101,268 and 119,478,282 shares issued; and 125,048,396 and 119,458,674 shares outstanding, respectively +1,251 1,194 +Additional paid-in capital 2,533,247 2,133,172 +Retained earnings 2,556,987 1,776,541 +Treasury stock, at cost, 52,872 and 19,608 shares, respectively +( 2,336 ) ( 45 ) +Total Matador Resources Company shareholders’ equity 5,089,149 3,910,862 +Non-controlling interest in subsidiaries 368,283 216,826 +Total shareholders’ equity 5,457,432 4,127,688 +Total liabilities and shareholders’ equity $ 10,850,109 $ 7,726,996 +The accompanying notes are an integral part of these consolidated financial statements. +F-5 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share data) +Year Ended December 31, +2024 2023 2022 +Revenues +Oil and natural gas revenues $ 3,143,834 $ 2,545,599 $ 2,905,738 +Third-party midstream services revenues 141,027 122,153 90,606 +Sales of purchased natural gas 194,097 149,869 200,355 +Realized gain (loss) on derivatives 12,724 ( 9,575 ) ( 157,483 ) +Unrealized gain (loss) on derivatives 13,299 ( 1,261 ) 18,809 +Total revenues 3,504,981 2,806,785 3,058,025 +Expenses +Production taxes, transportation and processing 306,751 264,493 282,193 +Lease operating 341,544 243,655 157,105 +Plant and other midstream services operating 171,492 128,910 95,522 +Purchased natural gas 142,715 129,401 178,937 +Depletion, depreciation and amortization 974,300 716,688 466,348 +Accretion of asset retirement obligations 6,027 3,943 2,421 +General and administrative 127,454 110,373 116,229 +Total expenses 2,070,283 1,597,463 1,298,755 +Operating income 1,434,698 1,209,322 1,759,270 +Other income (expense) +Net loss on asset sales and impairment — ( 202 ) ( 1,311 ) +Interest expense ( 171,687 ) ( 121,520 ) ( 67,164 ) +Other income (expense) 696 8,785 ( 5,121 ) +Total other expense ( 170,991 ) ( 112,937 ) ( 73,596 ) +Income before income taxes 1,263,707 1,096,385 1,685,674 +Income tax provision (benefit) +Current 27,059 13,922 54,877 +Deferred 265,305 172,104 344,480 +Total income tax provision 292,364 186,026 399,357 +Net income 971,343 910,359 1,286,317 +Net income attributable to non-controlling interest in subsidiaries ( 86,021 ) ( 64,285 ) ( 72,111 ) +Net income attributable to Matador Resources Company shareholders $ 885,322 $ 846,074 $ 1,214,206 +Earnings per common share +Basic $ 7.16 $ 7.10 $ 10.28 +Diluted $ 7.14 $ 7.05 $ 10.11 +Weighted average common shares outstanding +Basic 123,568 119,139 118,122 +Diluted 124,076 119,980 120,131 +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands) +For the Years Ended December 31, 2024, 2023 and 2022 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital (Accumulated deficit) retained earnings Treasury Stock Non-controlling interest in subsidiaries +Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2022 117,862 $ 1,179 $ 2,077,592 $ ( 171,318 ) 12 $ ( 243 ) $ 1,907,210 $ 220,178 $ 2,127,388 +Dividends declared ($ 0.30 per share) +— — — ( 35,246 ) — — ( 35,246 ) — ( 35,246 ) +Issuance of common stock pursuant to employee stock compensation plan 1,001 10 ( 11,544 ) — — — ( 11,534 ) — ( 11,534 ) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 25 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 20,224 — — — 20,224 — 20,224 +Stock options exercised, net of options forfeited in net share settlements 157 2 ( 4,007 ) — — — ( 4,005 ) — ( 4,005 ) +Restricted stock forfeited — — — — 85 ( 2,376 ) ( 2,376 ) — ( 2,376 ) +Contribution related to formation of San Mateo, net of tax of $ 5.9 million (See Note 11) +— — 22,318 — — — 22,318 — 22,318 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 85,995 ) ( 85,995 ) +Cancellation of treasury stock ( 92 ) ( 1 ) ( 2,584 ) — ( 92 ) 2,585 — — — +Current period net income — — — 1,214,206 — — 1,214,206 72,111 1,286,317 +Balance at December 31, 2022 118,953 1,190 2,101,999 1,007,642 5 ( 34 ) 3,110,797 206,294 3,317,091 +Dividends declared ($ 0.65 per share) +— — — ( 77,175 ) — — ( 77,175 ) — ( 77,175 ) +Issuance of common stock pursuant to employee stock compensation plan 623 6 ( 15,560 ) — — — ( 15,554 ) — ( 15,554 ) +Issuance of common stock pursuant to directors’ and advisors’ compensation plan 11 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 21,580 — — — 21,580 — 21,580 +Stock options exercised, net of options forfeited in net share settlements 22 — 49 — — — 49 — 49 +Restricted stock forfeited — — — — 146 ( 5,087 ) ( 5,087 ) — ( 5,087 ) +Contribution related to formation of San Mateo, net of tax of $ 8.0 million (See Note 11) +— — 30,178 — — — 30,178 — 30,178 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — 24,500 24,500 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 78,253 ) ( 78,253 ) +Cancellation of treasury stock ( 131 ) ( 2 ) ( 5,074 ) — ( 131 ) 5,076 — — — +Current period net income — — — 846,074 — — 846,074 64,285 910,359 +Balance at December 31, 2023 119,478 $ 1,194 $ 2,133,172 $ 1,776,541 20 $ ( 45 ) $ 3,910,862 $ 216,826 $ 4,127,688 +Total shareholders’ equity attributable to Matador Resources Company +Additional +paid-in +capital (Accumulated deficit) retained earnings Treasury Stock Non-controlling interest in subsidiaries Total shareholders’ equity +Common Stock +Shares Amount Shares Amount +Balance at January 1, 2024 119,478 $ 1,194 $ 2,133,172 $ 1,776,541 20 $ ( 45 ) $ 3,910,862 $ 216,826 $ 4,127,688 +Dividends declared ($ 0.85 per share) +— — — ( 104,876 ) — — ( 104,876 ) — ( 104,876 ) +Issuance of common stock pursuant to employee stock compensation plan 426 4 ( 9,205 ) — — — ( 9,201 ) — ( 9,201 ) +Issuance of common stock pursuant to public offering 5,250 53 344,610 — — — 344,663 — 344,663 +Cost to issue equity — — ( 2,566 ) — — — ( 2,566 ) — ( 2,566 ) +Issuance of common stock pursuant to directors’ compensation plan 17 — — — — — — — — +Stock-based compensation expense related to equity-based awards including amounts capitalized — — 23,749 — — — 23,749 — 23,749 +Stock options exercised, net of options forfeited in net share settlements 12 — — — — — — — — +Restricted stock forfeited — — — — 115 ( 5,319 ) ( 5,319 ) — ( 5,319 ) +Contribution of Pronto to San Mateo (See Note 11) — — 27,713 — — — 27,713 143,787 171,500 +Contributions related to formation of San Mateo, net of tax of $ 5.0 million (See Note 11) +— — 18,802 — — — 18,802 — 18,802 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — 19,110 19,110 +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries — — — — — — — ( 97,461 ) ( 97,461 ) +Cancellation of treasury stock ( 82 ) — ( 3,028 ) — ( 82 ) 3,028 — — — +Current period net income — — — 885,322 — — 885,322 86,021 971,343 +Balance at December 31, 2024 125,101 $ 1,251 $ 2,533,247 $ 2,556,987 53 $ ( 2,336 ) $ 5,089,149 $ 368,283 $ 5,457,432 +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +Table of Contents +Matador Resources Company and Subsidiaries +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2024 2023 2022 +Operating activities +Net income $ 971,343 $ 910,359 $ 1,286,317 +Adjustments to reconcile net income (loss) to net cash provided by operating activities +Unrealized (gain) loss on derivatives ( 13,299 ) 1,261 ( 18,809 ) +Depletion, depreciation and amortization 974,300 716,688 466,348 +Accretion of asset retirement obligations 6,027 3,943 2,421 +Stock-based compensation expense 14,982 13,661 15,123 +Deferred income tax provision 265,305 172,104 344,480 +Amortization of debt issuance cost and other debt related costs 16,533 7,047 ( 517 ) +Other non-cash changes ( 1,386 ) ( 7,262 ) 1,311 +Changes in operating assets and liabilities +Accounts receivable, prepaid expenses and other current assets ( 138,137 ) 48,136 ( 228,378 ) +Lease and well equipment inventory ( 10,934 ) ( 3,034 ) ( 2,847 ) +Other long-term assets 4,052 646 175 +Accounts payable, accrued liabilities and other current liabilities 33,748 2,810 63,455 +Royalties payable 56,193 34,273 23,339 +Advances from joint interest owners 63,384 ( 32,402 ) 34,283 +Other long-term liabilities 4,774 ( 402 ) ( 7,962 ) +Net cash provided by operating activities 2,246,885 1,867,828 1,978,739 +Investing activities +Drilling, completion and equipping capital expenditures ( 1,222,831 ) ( 1,192,800 ) ( 771,830 ) +Acquisition of Advance — ( 1,676,132 ) — +Acquisition of Ameredev ( 1,831,214 ) — — +Acquisition of oil and natural gas properties ( 454,443 ) ( 187,655 ) ( 155,074 ) +Midstream capital expenditures ( 283,881 ) ( 165,719 ) ( 80,051 ) +Acquisition of midstream assets — — ( 75,816 ) +Expenditures for other property and equipment ( 5,691 ) ( 3,636 ) ( 1,213 ) +Proceeds from sale of assets and other 12,370 14,750 46,507 +Proceeds from sale of equity method investment 113,576 — — +Net cash used in investing activities ( 3,672,114 ) ( 3,211,192 ) ( 1,037,477 ) +Financing activities +Repayments of borrowings under Credit Agreement ( 3,969,500 ) ( 3,032,000 ) ( 300,000 ) +Borrowings under Credit Agreement 4,065,000 3,532,000 200,000 +Repayments of borrowings under San Mateo Credit Facility ( 733,000 ) ( 171,000 ) ( 150,000 ) +Borrowings under San Mateo Credit Facility 826,000 228,000 230,000 +Cost to enter into or amend credit facilities ( 33,436 ) ( 9,296 ) ( 3,725 ) +Proceeds from issuance of senior unsecured notes 1,650,000 494,800 — +Issuance costs of senior unsecured notes ( 28,157 ) ( 8,503 ) — +Proceeds from issuance of common stock 344,663 — — +Purchase of senior unsecured notes ( 699,191 ) — ( 344,302 ) +Dividends paid ( 104,876 ) ( 77,175 ) ( 35,246 ) +Contribution related to Pronto Transaction 171,500 — — +Contributions related to formation of San Mateo 23,800 38,200 28,250 +Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries 19,110 24,500 — +Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries ( 97,461 ) ( 78,253 ) ( 85,995 ) +Taxes paid related to net share settlement of stock-based compensation ( 16,956 ) ( 22,910 ) ( 19,242 ) +Other ( 3,823 ) ( 16,031 ) ( 592 ) +Net cash provided by (used in) financing activities 1,413,673 902,332 ( 480,852 ) +(Decrease) increase in cash and restricted cash ( 11,556 ) ( 441,032 ) 460,410 +Cash and restricted cash at beginning of period 106,298 547,330 86,920 +Cash and restricted cash at end of period $ 94,742 $ 106,298 $ 547,330 +Supplemental disclosures of cash flow information (Note 15) +The accompanying notes are an integral part of these consolidated financial statements. +F-8 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +December 31, 2024, 2023 and 2022 +NOTE 1 — NATURE OF OPERATIONS +Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations primarily through its midstream joint venture, San Mateo Midstream, LLC and its subsidiaries (“San Mateo”) in support of, and to provide flow assurance for, the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Basis of Presentation +The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810) . The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation. +Use of Estimates +The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates in the purchase price allocations and of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. +Restricted Cash +Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. +Accounts Receivable +The Company sells its operated oil, natural gas and natural gas liquids (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, customers of San Mateo or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production +F-9 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. +The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. +For the year ended December 31, 2024, three significant purchasers accounted for 79 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 53 %), Exxon Mobil Corporation ( 15 %) and Enterprise Products Partners L.P. ( 11 %). For the year ended December 31, 2023, three significant purchasers accounted for 76 % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. ( 42 %), Exxon Mobil Corporation ( 24 %), and Enterprise Products Partners L.P. ( 10 %). For the year ended December 31, 2022, three significant purchasers accounted for 70 % of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation ( 34 %), Plains Marketing, L.P. ( 27 %) and BP America Production Company ( 9 %). If any one of Matador’s major customers were to stop purchasing its production, the Company believes there are a number of other purchasers to whom the Company could sell Matador’s production. If multiple significant customers were to discontinue purchasing Matador’s production abruptly, the Company believes it would have the resources needed to access alternative customers or markets and avoid or materially mitigate associated sales disruptions. At December 31, 2024, 2023 and 2022, approximately 32 %, 38 % and 29 %, respectively, of the Company’s accounts receivable, including joint interest billings, related to the top three purchasers. +Lease and Well Equipment Inventory +Lease and well equipment inventory is stated at the lower of cost or net realizable value and consists entirely of materials or equipment scheduled for use in future well or midstream operations. +Oil and Natural Gas Properties +The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $ 66.6 million, $ 54.2 million and $ 47.8 million of its general and administrative costs into oil and natural gas properties in 2024, 2023 and 2022, respectively. The Company capitalized $ 17.5 million, $ 20.2 million and $ 10.1 million of its interest expense into oil and natural gas properties for the years ended December 31, 2024, 2023 and 2022, respectively. +Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2024, 2023 and 2022, the Company recorded depletion expense of $ 925.6 million, $ 672.0 million and $ 428.9 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. +Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. +Ceiling Test +The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: +F-10 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(a) the present value, discounted at 10 %, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus +(b) unproved and unevaluated property costs not being amortized, plus +(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less +(d) any income tax effects related to the properties involved. +Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes. +The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period, and a 10 % discount factor is used to determine the present value of future net revenues. For the period from January through December 2024, these average oil and natural gas prices were $ 71.96 per Bbl and $ 2.13 per MMBtu, respectively. For the period from January through December 2023, these average oil and natural gas prices were $ 74.70 per Bbl and $ 2.64 per MMBtu, respectively. For the period from January through December 2022, these average oil and natural gas prices were $ 90.15 per Bbl and $ 6.36 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. +During the years ended December 31, 2024, 2023 and 2022, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2024, 2023 and 2022. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. +Midstream Properties and Other Property and Equipment +Midstream properties and other property and equipment are recorded at historical cost or acquisition date fair value and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. The Company capitalized $ 3.4 million, $ 2.9 million and $ 2.2 million of general and administrative costs into midstream properties in 2024, 2023 and 2022, respectively. The Company capitalized $ 12.2 million and $ 2.1 million of interest expense into midstream properties for the years ended December 31, 2024 and 2023, respectively. The Company did no t capitalize any interest expense into midstream properties for the year ended December 31, 2022. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment. +The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions. +Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of income. +F-11 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Asset Retirement Obligations +The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of income. +Derivative Financial Instruments +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of income. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of income. See Note 12 for additional information about the Company’s derivative instruments. +Revenues +The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. +The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of income, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of income, as they represent payment for services performed outside of the contract with the customer. +The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue natural gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue natural gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of income. +The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) +F-12 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +(“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. +The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Marlan cryogenic natural gas processing plant in Eddy County, New Mexico (the “Marlan Processing Plant”) or Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue natural gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of income as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold. +From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of income. +The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2024, 2023 and 2022 (in thousands). +Year Ended December 31, +2024 2023 2022 +Revenues from contracts with customers $ 3,478,958 $ 2,817,621 $ 3,196,699 +Realized gain (loss) on derivatives 12,724 ( 9,575 ) ( 157,483 ) +Unrealized gain (loss) on derivatives 13,299 ( 1,261 ) 18,809 +Total revenues $ 3,504,981 $ 2,806,785 $ 3,058,025 +Year Ended December 31, +2024 2023 2022 +Oil revenues $ 2,772,360 $ 2,144,894 $ 2,113,606 +Natural gas revenues 371,474 400,705 792,132 +Third-party midstream services revenues 141,027 122,153 90,606 +Sales of purchased natural gas 194,097 149,869 200,355 +Total revenues from contracts with customers $ 3,478,958 $ 2,817,621 $ 3,196,699 +The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. +Stock-Based Compensation +The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors (the “Board”) and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of income or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration, development and midstream activities. Awards that are expected to be settled in cash are liability-based awards, which are +F-13 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of income or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration, development and midstream activities. +The Company uses the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”). +The Company’s consolidated statements of income for the years ended December 31, 2024, 2023 and 2022 include an equity-based compensation (non-cash) expense of $ 15.0 million, $ 13.7 million and $ 15.1 million, respectively. This equity-based compensation expense includes common stock issuances and restricted stock units expense totaling $ 1.3 million, $ 1.2 million and $ 1.0 million for the years ended December 31, 2024, 2023 and 2022, respectively, paid to independent members of the Board and advisors as compensation for their services to the Company. +Income Taxes +The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. +The Company recognizes tax benefits from an uncertain tax position on the basis of a two-step process in which (i) the Company determines whether it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position and (ii) for those tax positions that meet the more-likely-than-not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. +When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of income. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2024, 2023 and 2022. +Allocation of Purchase Price in Business Combinations +As part of the Company’s business strategy, it periodically pursues the acquisition of midstream assets and oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. +Earnings Per Common Share +The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. +F-14 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2024, 2023 and 2022 (in thousands, except per share data). +Year Ended December 31, +2024 2023 2022 +Net income attributable to Matador Resources Company shareholders — numerator $ 885,322 $ 846,074 $ 1,214,206 +Weighted average common shares outstanding — denominator +Basic 123,568 119,139 118,122 +Dilutive effect of options and restricted stock units 508 841 2,009 +Diluted weighted average common shares outstanding 124,076 119,980 120,131 +Earnings per common share attributable to Matador Resources Company shareholders +Basic $ 7.16 $ 7.10 $ 10.28 +Diluted $ 7.14 $ 7.05 $ 10.11 +Credit Risk +The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. +The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2024 were with Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof), which are all lenders under the Company’s reserves-based revolving credit agreement (the “Credit Agreement”). +Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. +Recent Accounting Pronouncements +Segments . In November 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures , which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023 and for interim periods within fiscal years beginning after December 15, 2024. During the fourth quarter of 2024, the Company adopted this ASU, which modified the Company’s disclosures but did not have an impact on the Company’s consolidated balance sheets, or statements of income or cash flows in its consolidated financial statements. See Note 16 for additional disclosures related to segments. +Income Taxes . In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures , which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid. This ASU is effective for the Company prospectively to all annual periods beginning after December 15, 2024. The Company is currently evaluating the impact of this standard on its disclosures. +F-15 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued +Climate-Related Disclosures. On March 6, 2024, the SEC adopted a new set of rules that require a wide range of climate-related disclosures, including material climate-related risks, information on any climate-related targets or goals that are material to the registrant’s business, results of operations or financial condition, Scope 1 and Scope 2 greenhouse gas emissions on a phased-in basis by certain larger registrants when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Compliance dates under the final rule are phased in by registrant category. Multiple lawsuits have been filed challenging the SEC’s new climate rules, and on April 4, 2024, the SEC issued an order staying implementation of the final rules until judicial review is complete. The Company is currently evaluating the impact of the final rules, if implemented, on its disclosures . +Disaggregation of Income Statement Expenses. In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses . The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depreciation, depletion and amortization recognized as part of oil and gas producing activities and employee compensation. This ASU is effective for the Company to all annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The Company is currently evaluating the impact of this standard on its disclosures. +NOTE 3 — PROPERTY AND EQUIPMENT +The following table presents a summary of the Company’s property and equipment balances as of December 31, 2024 and 2023 (in thousands). +December 31, +2024 2023 +Oil and natural gas properties +Evaluated (subject to amortization) $ 12,534,290 $ 9,633,757 +Unproved and unevaluated (not subject to amortization) 1,702,203 1,193,257 +Total oil and natural gas properties 14,236,493 10,827,014 +Accumulated depletion ( 5,959,845 ) ( 5,034,243 ) +Net oil and natural gas properties 8,276,648 5,792,771 +Midstream properties +Midstream equipment and facilities 1,683,334 1,318,015 +Accumulated depreciation ( 211,048 ) ( 167,116 ) +Net midstream properties 1,472,286 1,150,899 +Other property and equipment +Furniture, fixtures and other equipment 20,007 17,985 +Software 8,283 8,241 +Leasehold improvements 19,242 14,149 +Total other property and equipment 47,532 40,375 +Accumulated depreciation ( 32,370 ) ( 27,604 ) +Net other property and equipment 15,162 12,771 +Net property and equipment $ 9,764,096 $ 6,956,441 +F-16 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 3 — PROPERTY AND EQUIPMENT — Continued +The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2024 and the year in which these costs were incurred (in thousands). +Description 2024 2023 2022 2021 2020 and prior Total +Costs incurred for +Property acquisition $ 587,977 $ 324,176 $ 97,748 $ 108,010 $ 474,978 $ 1,592,889 +Exploration wells 44,512 1,943 612 101 639 47,807 +Development wells 57,874 1,480 578 317 1,258 61,507 +Total $ 690,363 $ 327,599 $ 98,938 $ 108,428 $ 476,875 $ 1,702,203 +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. +Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2024 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. +Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $ 109.3 million at December 31, 2024. Of this total, $ 47.8 million was associated with exploration wells and $ 61.5 million was associated with development wells. The Company anticipates that most of the $ 109.3 million associated with these wells in progress at December 31, 2024 will be transferred to the amortization base during 2025. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2024 are costs related to the advanced preparation for wells that the Company intends to drill in the future. +NOTE 4 — LEASES +The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2024 were 5.48 % and 7.23 % for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets. +F-17 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated statement of income information related to lease expenses, on a gross basis, for the years ended December 31, 2024 and 2023, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells. +Year Ended December 31, +2024 2023 +Operating leases +Lease operating $ 30,141 $ 25,637 +Plant and other midstream services — 360 +General and administrative 2,910 2,933 +Total operating leases (1) +33,051 28,930 +Short-term leases +Lease operating 46,770 27,252 +Plant and other midstream services 11,110 5,590 +General and administrative 54 63 +Total short-term leases (2)(3) +57,934 32,905 +Financing leases +Depreciation of assets 2,296 2,765 +Interest on lease liabilities 607 410 +Total financing leases 2,903 3,175 +Total lease expense $ 93,888 $ 65,010 +_____________________ +(1) Does not include gross payments related to drilling rig leases of $ 87.8 million and $ 84.1 million for the years ended December 31, 2024 and 2023, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2024 and 2023, respectively. +(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases. +(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $ 231.8 million and $ 159.7 million for the years ended December 31, 2024 and 2023, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2024 and 2023, respectively. +F-18 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 4 — LEASES — Continued +The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2024 and 2023, respectively (in thousands). +December 31, +2024 2023 +Operating leases +Other long-term assets $ 127,445 $ 44,404 +Other current liabilities $ ( 57,924 ) $ ( 36,946 ) +Other long-term liabilities ( 72,498 ) ( 10,800 ) +Total operating lease liabilities $ ( 130,422 ) $ ( 47,746 ) +Financing leases +Other property and equipment, at cost $ 12,783 $ 11,316 +Accumulated depreciation ( 9,532 ) ( 7,236 ) +Net property and equipment $ 3,251 $ 4,080 +Other current liabilities $ ( 1,312 ) $ ( 1,254 ) +Other long-term liabilities ( 1,021 ) ( 869 ) +Total financing lease liabilities $ ( 2,333 ) $ ( 2,123 ) +The following table presents supplemental consolidated cash flow information related to lease payments for the years ended December 31, 2024 and 2023, respectively (in thousands). +Year Ended December 31, +2024 2023 +Cash paid related to lease liabilities +Operating cash payments for operating leases $ 37,155 $ 28,766 +Investing cash payments for operating leases $ 87,776 $ 84,065 +Financing cash payments for financing leases $ 1,257 $ 1,082 +Right of use assets obtained in exchange for lease obligations entered into during the period +Operating leases $ 207,279 $ 87,042 +Financing leases $ 1,467 $ 3,891 +The following table presents the maturities of lease liabilities at December 31, 2024 (in years). +Weighted-Average Remaining Lease Term December 31, 2024 +Operating leases 7.4 +Financing leases 1.8 +F-19 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 4 — LEASES — Continued +The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2024 (in thousands). +December 31, 2024 +Operating Leases Financing Leases +2025 $ 57,924 $ 1,312 +2026 18,498 812 +2027 12,397 365 +2028 5,842 — +2029 5,318 — +Thereafter 61,694 — +Total lease payments 161,673 2,489 +Less imputed interest ( 31,251 ) ( 156 ) +Total lease obligations 130,422 2,333 +Less current obligations ( 57,924 ) ( 1,312 ) +Long-term lease obligations $ 72,498 $ 1,021 +NOTE 5 — ASSET RETIREMENT OBLIGATIONS +The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. +The following table summarizes the changes in the Company’s asset retirement obligations for the years ended +December 31, 2024 and 2023 (in thousands). +Year Ended December 31, +2024 2023 +Beginning asset retirement obligations $ 92,090 $ 53,741 +Liabilities incurred during period 7,538 6,944 +Liabilities settled during period ( 1,188 ) ( 1,634 ) +Revisions in estimated cash flows 16,351 21,642 +Acquisitions during the period 7,487 8,326 +Divestitures during the period ( 5,637 ) ( 872 ) +Accretion expense 6,027 3,943 +Ending asset retirement obligations 122,668 92,090 +Less: current asset retirement obligations (1) +( 8,431 ) ( 4,605 ) +Long-term asset retirement obligations $ 114,237 $ 87,485 +__________________ +(1) Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2024 and 2023. +F-20 +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES +Business Combinations +Joint Venture +On December 18, 2024, the Company completed a transaction with Five Point Energy, LLC and its affiliates (“Five Point”) in which the Company contributed Pronto Midstream, LLC and its subsidiary (“Pronto”), a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $ 171.5 million (the “Pronto Transaction”). In connection with the Pronto Transaction, the Company received a special distribution from San Mateo of approximately $ 219.8 million. In addition, the Company has the potential to earn up to $ 75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51 % by the Company and 49 % by Five Point with Five Point’s interest in San Mateo being accounted for as a non-controlling interest. +Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. +In connection with the Pronto Transaction, the Company dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from the Company’s operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind Midstream Partners LLC (“Northwind”), an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing. +Ameredev Acquisition +On September 18, 2024, a wholly-owned subsidiary of the Company completed the acquisition (the “Ameredev Acquisition”) of Ameredev Stateline II, LLC (“Ameredev”) from affiliates of EnCap Investments L.P., including (i) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (ii) an approximate 19 % stake (the “Piñon Investment”) in the parent company of Piñon Midstream, LLC (“Piñon”). The Ameredev Acquisition had an effective date of June 1, 2024 and an aggregate as-adjusted closing purchase price of approximately $ 1.83 billion in cash, which amount is subject to customary post-closing adjustments. The purchase price for the Ameredev Acquisition was funded by a combination of cash on hand and borrowings under the Company’s Credit Agreement, which was amended on September 18, 2024 to, among other things: (i) provide for a term loan of $ 250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitments under the revolving credit facility from $ 1.50 billion to $ 2.25 billion. On September 25, 2024, the Company completed the sale of $ 750.0 million in aggregate principal amount of the Company’s 6.25 % senior unsecured notes due 2033 (the “2033 Notes”) and used the net proceeds to partially repay borrowings outstanding under the Credit Agreement, including all of the $ 250.0 million in outstanding borrowings under the term loan. +The Ameredev Acquisition was accounted for under the acquisition method of accounting as a business combination in accordance with Accounting Standards Codification Topic 805, Business Combinations (“ASC Topic 805”). Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the respective acquisition date, with any excess purchase price allocated to goodwill. As the Company acquired 100 % of the membership interests of Ameredev, the acquisition was treated as an asset acquisition for tax purposes. The Company concluded that the Piñon Investment was an equity method investment. +The preliminary allocation of the total purchase price for the Ameredev Acquisition is set forth below (in thousands). As of the date of this filing, the valuation of the Piñon Investment and certain working capital adjustments in connection with the final settlement remain ongoing and adjustments may be made. The Company expects to complete the final purchase price allocation during the 12-month period subsequent to the Ameredev Acquisition closing date. +F-21 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +Consideration Allocation +Cash consideration given $ 1,831,214 +Allocation of purchase price +Current assets $ 51,314 +Oil and natural gas properties +Evaluated 1,316,532 +Unproved and unevaluated 312,904 +Midstream assets 117,762 +Equity method investment 118,407 +Current liabilities ( 79,372 ) +Asset retirement obligations ( 6,333 ) +Net assets acquired $ 1,831,214 +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of evaluated oil and natural gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. +Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) future production volumes, (ii) future commodity prices and (iii) recent market comparable transactions for unproved acreage. These inputs require significant judgments and estimates and are the most sensitive and subject to change. +The results of operations for the Ameredev Acquisition since the closing date have been included in the Company’s consolidated financial statements for the year ended December 31, 2024. The oil and natural gas production from Ameredev increased the Company’s revenues and net income for the period from September 18, 2024 through December 31, 2024 by $ 118.0 million and $ 34.8 million, respectively. +Pro Forma Information +The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the years ended December 31, 2024 and 2023, assuming the Ameredev Acquisition had been completed as of January 1, 2023. The pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations or the consolidated financial position of the Company would have been had the Ameredev Acquisition occurred on the dates noted above, nor is it necessarily indicative of the future results of operations or consolidated financial position of the Company. Future results may vary significantly from the results reflected because of various factors. +F-22 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on currently available information and certain estimates and assumptions that the Company believes provide a reasonable basis for presenting the significant effects of the Ameredev Acquisition, including (i) the increase in depletion reflecting the relative fair values and production volumes attributable to Ameredev’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (ii) adjustments to interest expense as a result of the incremental borrowings necessary to finance the Ameredev Acquisition and (iii) the estimated tax impacts of the pro-forma adjustments. The pro forma financial information does not reflect the benefits of projected synergies, potential cost savings or the costs that may be necessary to achieve such savings, opportunities to increase revenue generation or other factors that may result from the Ameredev Acquisition and, accordingly, does not attempt to predict or suggest future results. Management cannot identify the timing, nature and amount of such savings, costs or other factors, any of which could affect the future consolidated results of operations or consolidated financial position of the Company. +Year Ended +December 31, +2024 2023 +(In thousands, except per share data) +Total revenue $ 3,778,470 $ 3,371,170 +Net income attributable to Matador Resources Company shareholders $ 869,987 $ 841,591 +Earnings per share: +Basic $ 7.04 $ 7.06 +Diluted $ 7.01 $ 7.01 +Q1 2024 Acquisition +On February 15, 2024, a wholly-owned subsidiary of the Company acquired oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico (the “Q1 2024 Acquisition”). The Q1 2024 Acquisition had an effective date of October 1, 2023 and consideration for the acquisition consisted of an amount in cash equal to approximately $ 154.8 million. +The Q1 2024 Acquisition was accounted for under the acquisition method of accounting as a business combination in accordance with ASC Topic 805. Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the acquisition date, with any excess purchase price allocated to goodwill. +The final allocation of the total purchase price for the Q1 2024 Acquisition is set forth below (in thousands). +Consideration Allocation +Cash consideration given $ 154,821 +Allocation of purchase price +Current assets $ 3,358 +Oil and natural gas properties +Evaluated 45,778 +Unproved and unevaluated 106,839 +Asset retirement obligations ( 1,154 ) +Net assets acquired $ 154,821 +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of evaluated oil and natural gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. +F-23 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) future production volumes, (ii) future commodity prices and (iii) recent market comparable transactions for unproved acreage. These inputs require significant judgments and estimates and are the most sensitive and subject to change. +The results of operations for the Q1 2024 Acquisition since the closing date have been included in the Company’s consolidated financial statements for the year ended December 31, 2024. The pro forma impact of this business combination to revenues and net income for 2024 and 2023 would not be material to the Company’s 2024 or 2023 revenues and net income as reported. +Advance Acquisition +On April 12, 2023, a wholly-owned subsidiary of the Company completed the acquisition of Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas (the “Initial Advance Acquisition”). The Initial Advance Acquisition had an effective date of January 1, 2023 and an aggregate purchase price consisting of (i) an amount in cash equal to approximately $ 1.60 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $ 7.5 million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $ 85 per barrel (all such payments for the 12 months in 2023, the “Contingent Consideration”). The Cash Consideration was paid upon the closing of the Initial Advance Acquisition and was funded by a combination of cash on hand and borrowings under the Credit Agreement. The Company made no payments related to the Contingent Consideration during the first, second, or third quarters of 2023. In the fourth quarter of 2023, the Company paid Contingent Consideration of $ 15.0 million, as the average oil price for the months of September and October 2023 exceeded $ 85 per barrel. +The Company recorded the Contingent Consideration at fair value on the date of the business combination and recorded the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of income. The fair value of the Contingent Consideration was $ 21.2 million at April 12, 2023. The change in fair value of the Contingent Consideration included in “Other income (expense)” during the year ended December 31, 2023 was income of $ 6.2 million. The Company used the Monte Carlo simulation method to measure the fair value of the Contingent Consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy). +On December 1, 2023, the Company acquired additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition (the “Advance Royalty Acquisition”). The Advance Royalty Acquisition had an effective date of October 1, 2023 and an aggregate purchase price of approximately $ 81.0 million (which amount was subject to certain customary post-closing adjustments), and was funded by cash on hand. +The Initial Advance Acquisition and Advance Royalty Acquisition (collectively, the “Advance Acquisition”) were accounted for under the acquisition method of accounting as a business combination in accordance with ASC Topic 805. Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the respective acquisition dates, with any excess purchase price allocated to goodwill. The Advance Acquisition was treated as an asset acquisition for tax purposes, as the Company acquired 100 % of the membership interests of Advance in the Initial Advance Acquisition, and acquired additional overriding royalty interests and royalty interests in the Advance Royalty Acquisition. +F-24 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued +The final allocation of the total purchase price for the Advance Acquisition is set forth below (in thousands). +Consideration given +Allocation +Cash +$ 1,676,132 +Working capital adjustments ( 4,060 ) +Fair value of Contingent Consideration at April 12, 2023 21,151 +Total consideration given +$ 1,693,223 +Allocation of purchase price +Current assets $ 79,287 +Oil and natural gas properties +Evaluated +1,418,668 +Unproved and unevaluated +213,835 +Midstream assets +63,644 +Current liabilities ( 73,885 ) +Asset retirement obligations +( 8,326 ) +Net assets acquired +$ 1,693,223 +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. +Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) future production volumes, (ii) expected operating and development costs, (iii) future commodity prices, (iv) recent market comparable transactions for unproved acreage and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change. +Divestitures +During 2024 and 2023, the Company converted approximately $ 12.4 million and $ 0.7 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana. +On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. The Company received $ 113.6 million from the sale of Piñon during the fourth quarter of 2024 and used these proceeds to reduce borrowings under the Credit Agreement. The Company currently expects to receive an additional $ 4.8 million from the sale of Piñon in the first half of 2025. +F-25 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT +The components of debt, including the effects of issuance costs and discounts, net as of December 31, 2024 and 2023, are set forth below (in thousands). +December 31, +2024 2023 +Revolving credit agreements: +Credit Agreement due 2029 $ 595,500 $ 500,000 +San Mateo Credit Facility due 2029 615,000 522,000 +Senior unsecured notes: +5.875 % senior notes due 2026 +— 699,191 +6.875 % senior notes due 2028 +500,000 500,000 +6.500 % senior notes due 2032 +900,000 — +6.250 % senior notes due 2033 +750,000 — +Issuance costs and discounts, net ( 35,092 ) ( 14,564 ) +Total senior unsecured notes payable 2,114,908 1,184,627 +Total long-term debt $ 3,325,408 $ 2,206,627 +Credit Agreements +MRC Energy Company +On November 18, 2021, the Company entered into its Fourth Amended and Restated Credit Agreement with the lenders party thereto, then led by Truist Bank as administrative agent. MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85 % of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo is not a guarantor of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The outstanding borrowings under the Credit Agreement mature on March 22, 2029 or, if earlier, the date that is up to 180 days prior to the earliest stated redemption date of any senior notes of the Company if unused availability under the revolving credit facility on such date is less than 20 % of the aggregate revolving commitments, on a pro forma basis after giving effect to the repayment of such senior notes. +The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. +On March 22, 2024, the Company and its lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $ 2.50 billion, (ii) increase the elected borrowing commitments from $ 1.325 billion to $ 1.50 billion, (iii) increase the maximum facility amount from $ 2.00 billion to $ 3.50 billion, (iv) extend the maturity date from October 31, 2026 to March 22, 2029, (v) appoint PNC Bank, National Association as administrative agent thereunder and (vi) add five new banks to the lending group. This March 2024 reaffirmation of the borrowing base constituted the regularly scheduled May 1 redetermination. +On September 18, 2024, the Company and its lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) provide for a term loan of $ 250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitments under the revolving credit facility from $ 1.50 billion to $ 2.25 billion. On September 25, 2024, the Company completed the sale of $ 750.0 million in aggregate principal amount of the 2033 Notes and used the proceeds to partially repay borrowings under the Credit Agreement, including all of the $ 250.0 million in outstanding borrowings under the term loan. +F-26 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +On November 21, 2024, the Company received notice from PNC Bank, National Association, as administrative agent under the Credit Agreement, that the lenders under the Credit Agreement completed their scheduled semi-annual review of the Company’s proved oil and natural gas reserves and unanimously determined to increase the borrowing base from $ 2.50 billion to $ 3.25 billion. The Company chose to maintain the elected borrowing commitments at $ 2.25 billion. +In the event of an increase in the elected borrowing commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . +Total deferred loan costs were $ 28.2 million at December 31, 2024, and these costs are being amortized over the term of the Credit Agreement. At December 31, 2024, the Company had $ 595.5 million in borrowings outstanding under the Credit Agreement and approximately $ 52.9 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 6.19 % at December 31, 2024. +The applicable interest rate margin for borrowings under the Credit Agreement ranges from 1.75 % to 2.75 % for borrowings bearing interest with reference to the Adjusted Term SOFR Rate (as defined in the Credit Agreement) and from 0.75 % to 1.75 % for borrowings bearing interest with reference to the Alternate Base Rate (as defined in the Credit Agreement), in each case depending on the level of borrowings under the Credit Agreement. In addition, the Adjusted Term SOFR Rate includes a credit spread adjustment of 0.10 % for all interest periods. The interest period for Adjusted Term SOFR Rate borrowings may be one , three or six months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition. +A commitment fee of 0.375 % to 0.50 %, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $ 150 million or 10 % of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. +Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including the following: +• incur indebtedness or grant liens on any of its assets; +• enter into commodity hedging agreements or interest rate agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +• engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and +• take certain actions with respect to the Company’s senior unsecured notes. +If an event of default exists under the Credit Agreement, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include the following: +• failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods; +F-27 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +• failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and +• a change of control, as defined in the Credit Agreement. +The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2024. +San Mateo Midstream, LLC +On December 19, 2018, San Mateo entered into a secured revolving credit facility (the “San Mateo Credit Facility”) with the lenders party thereto, currently led by Truist Bank as administrative agent. On November 26, 2024, San Mateo and its lenders entered into an amendment to the San Mateo Credit Facility to, among other things: (i) extend the maturity date of the facility from December 9, 2026 to November 26, 2029, (ii) increase the lender commitments from $ 535.0 million to $ 800.0 million and (iii) add six new banks to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in lender commitments to up to $ 1.05 billion. The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. +Total deferred loan costs were $ 8.9 million at December 31, 2024, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 6.44 % at December 31, 2024. At December 31, 2024, San Mateo had $ 615.0 million in borrowings outstanding under the San Mateo Credit Facility and $ 9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029. +Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or an Adjusted Term SOFR Rate loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50 %, and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor plus 1.0 %, plus, in each case, an amount ranging from 1.00 % to 2.00 % depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as an Adjusted Term SOFR Rate loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.00 % to 3.00 % depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition. +A commitment fee of 0.30 % to 0.50 %, depending on San Mateo’s Consolidated Total Leverage Ratio, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10 % of the lender commitments under the San Mateo Credit Facility. +Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including the following: +• incur indebtedness or grant liens on any of San Mateo’s assets; +• enter into hedging agreements; +• declare or pay dividends, distributions or redemptions; +• merge or consolidate; +• make any loans or investments; +• engage in transactions with affiliates; +F-28 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +• engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and +• issue equity interests in San Mateo or its restricted subsidiaries. +If an event of default exists under the San Mateo Credit Facility, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include the following: +• failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; +• failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods; +• bankruptcy or insolvency events involving San Mateo or its subsidiaries; and +• a change of control, as defined in the San Mateo Credit Facility. +The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024. +Senior Unsecured Notes +2026 Notes Tender Offer and Redemption +On April 2 and April 4, 2024, the Company completed the repurchase of an aggregate principal amount of approximately $ 556.3 million of the $ 699.2 million of outstanding senior notes due 2026 (the “2026 Notes”) pursuant to the Company’s cash tender offer for the 2026 Notes announced on March 26, 2024 (the “2026 Notes Tender Offer”). On April 2, 2024, the Company exercised its optional right, under the indenture governing the 2026 Notes, to redeem the remaining aggregate principal amount of approximately $ 142.9 million of 2026 Notes outstanding on September 15, 2024 (the “2026 Notes Redemption”) and, in connection therewith, to satisfy and discharge the Company’s obligations under such indenture with respect to the 2026 Notes. In connection with the 2026 Notes Tender Offer and 2026 Notes Redemption, the Company incurred a loss of approximately $ 3.0 million included in interest expense for the year ended December 31, 2024. +2028 Notes +At December 31, 2024, the Company had $ 500.0 million in aggregate principal amount of senior unsecured notes due 2028 (the “2028 Notes”), which have a 6.875 % coupon rate and mature on April 15, 2028. Interest on the 2028 Notes is payable semi-annually in arrears on each April 15 and October 15. The 2028 Notes are jointly and severally guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo is not a Restricted Subsidiary (as defined in the indenture governing the 2028 Notes (the “2028 Notes Indenture”)) or Guarantor of the 2028 Notes. +At any time prior to April 15, 2025, the Company may redeem up to 35 % in aggregate principal amount of 2028 Notes at a redemption price of 106.875 % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 65 % of the aggregate principal amount of the 2028 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2025, the Company may redeem all or part of the 2028 Notes for cash at a redemption price equal to 100 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date. +On or after April 15, 2025, the Company may redeem all or a part of the 2028 Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: +Year Redemption Price +2025 103.438 % +2026 101.719 % +2027 and thereafter 100.000 % +F-29 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +Subject to certain exceptions, the 2028 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2028 Notes Indenture) that is a Significant Subsidiary (as defined in the 2028 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2028 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding 2028 Notes may declare all the 2028 Notes to be due and payable immediately. Events of default include the following: +• default for 30 days in the payment when due of interest on the 2028 Notes; +• default in the payment when due of the principal of, or premium, if any, on the 2028 Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase 2028 Notes pursuant to the change of control or asset sale covenants of the 2028 Notes Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the 2028 Notes Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the 2028 Notes Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 100.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 100.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +2032 Notes +On April 2, 2024, the Company completed the sale of $ 900.0 million in aggregate principal amount of senior unsecured notes due 2032 (the “2032 Notes”), which have a 6.50 % coupon rate and mature on April 15, 2032. Interest on the 2032 Notes is payable in arrears on each April 15 and October 15. The 2032 Notes are jointly and severally guaranteed on a senior unsecured basis by the Guarantors. San Mateo is not a Restricted Subsidiary (as defined in the indenture governing the 2032 Notes (the “2032 Notes Indenture”)) or Guarantor of the 2032 Notes. +At any time prior to April 15, 2027, the Company may redeem up to 40 % in aggregate principal amount of 2032 Notes at a redemption price of 106.500 % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 60 % of the aggregate principal amount of the 2032 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2027, the Company may redeem all or part of the 2032 Notes for cash at a redemption price equal to 100 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date. +F-30 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +On or after April 15, 2027, the Company may redeem all or a part of the 2032 Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: +Year Redemption Price +2027 103.250 % +2028 101.625 % +2029 and thereafter 100.000 % +Subject to certain exceptions, the 2032 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2032 Notes Indenture) that is a Significant Subsidiary (as defined in the 2032 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2032 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding 2032 Notes may declare all the 2032 Notes to be due and payable immediately. Events of default include the following: +• default for 30 days in the payment when due of interest on the 2032 Notes; +• default in the payment when due of the principal of, or premium, if any, on the 2032 Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase 2032 Notes pursuant to the change of control or asset sale covenants of the 2032 Notes Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the 2032 Notes Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the 2032 Notes Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 100.0 million or more; +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 100.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +F-31 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +2033 Notes +On September 25, 2024, the Company completed the sale of $ 750.0 million in aggregate principal amount of the 2033 Notes, which have a 6.25 % coupon rate and mature on April 15, 2033. Interest on the 2033 Notes is payable in arrears on each April 15 and October 15. The first interest payment date for the 2033 Notes will be April 15, 2025. The 2033 Notes are jointly and severally guaranteed on a senior unsecured basis by the Guarantors. San Mateo is not a Restricted Subsidiary (as defined in the indenture governing the 2033 Notes (the “2033 Notes Indenture”)) or Guarantor of the 2033 Notes. +At any time prior to April 15, 2028, the Company may redeem up to 40 % in aggregate principal amount of 2033 Notes at a redemption price of 106.250 % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 60 % of the aggregate principal amount of the 2033 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2028, the Company may redeem all or part of the 2033 Notes for cash at a redemption price equal to 100 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date. +On or after April 15, 2028, the Company may redeem all or a part of the 2033 Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: +Year Redemption Price +2028 103.125 % +2029 101.563 % +2030 and thereafter 100.000 % +Subject to certain exceptions, the 2033 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including the following: +• incur additional indebtedness; +• sell assets; +• pay dividends or make certain investments; +• create liens that secure indebtedness; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2033 Notes Indenture) that is a Significant Subsidiary (as defined in the 2033 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2033 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25 % in principal amount of the then outstanding 2033 Notes may declare all the 2033 Notes to be due and payable immediately. Events of default include the following: +• default for 30 days in the payment when due of interest on the 2033 Notes; +• default in the payment when due of the principal of, or premium, if any, on the 2033 Notes; +• failure by the Company to comply with its obligations to offer to purchase or purchase 2032 Notes pursuant to the change of control or asset sale covenants of the 2033 Notes Indenture or to comply with the covenant relating to mergers; +• failure by the Company for 180 days after notice to comply with its reporting obligations under the 2033 Notes Indenture; +• failure by the Company for 60 days after notice to comply with any of the other agreements in the 2033 Notes Indenture; +• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ 100.0 million or more; +F-32 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 7 — DEBT — Continued +• failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ 100.0 million within 60 days; +• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and +• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. +NOTE 8 — INCOME TAXES +Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2024 and 2023 is as follows (in thousands). +December 31, +2024 2023 +Deferred tax assets +Net operating loss carryforwards $ 14,338 $ 14,387 +Compensation 16,562 13,303 +Research and experimental tax credits, net of reserve 1,117 12,638 +Lease liabilities 31,843 9,723 +Interest expense carryforward 15,891 170 +Other 1,677 281 +Total deferred tax assets 81,428 50,502 +Valuation allowance on deferred tax assets ( 11,957 ) ( 12,556 ) +Total deferred tax assets, net of valuation allowance 69,471 37,946 +Deferred tax liabilities +Property and equipment ( 802,186 ) ( 534,538 ) +Less than wholly-owned subsidiaries ( 75,580 ) ( 71,735 ) +Lease right of use assets ( 31,843 ) ( 9,723 ) +Unrealized gain on derivatives ( 4,039 ) ( 676 ) +Other ( 3,489 ) ( 2,713 ) +Total deferred tax liabilities ( 917,137 ) ( 619,385 ) +Net deferred tax liabilities $ ( 847,666 ) $ ( 581,439 ) +The current income tax provision and the deferred income tax provision for the years ended December 31, 2024, 2023 and 2022 were comprised of the following (in thousands). +Year Ended December 31, +2024 2023 2022 +Current income tax provision +Federal income tax $ 21,296 $ 1,554 $ 31,335 +State income tax 5,763 12,368 23,542 +Net current income tax provision $ 27,059 $ 13,922 $ 54,877 +Deferred income tax provision +Federal income tax $ 221,356 $ 145,711 $ 302,486 +State income tax 43,949 26,393 41,994 +Net deferred income tax provision $ 265,305 $ 172,104 $ 344,480 +F-33 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 8 — INCOME TAXES — Continued +Reconciliations of the tax expense computed at the statutory federal rate to the Company’s total income tax provision for the years ended December 31, 2024, 2023 and 2022 is as follows (in thousands). +Year Ended December 31, +2024 2023 2022 +Federal tax expense at statutory rate (1) +$ 265,379 $ 230,241 $ 353,992 +State income tax expense 47,242 38,525 59,870 +Permanent differences ( 3,931 ) 3,558 ( 84 ) +Non-controlling interest in subsidiaries ( 18,064 ) ( 13,500 ) ( 15,143 ) +Research and experimental tax credits 3,338 ( 109,368 ) — +Change in reserve on uncertain tax positions ( 1,001 ) 35,336 — +Change in state valuation allowance ( 599 ) 1,234 722 +Total income tax provision $ 292,364 $ 186,026 $ 399,357 +__________________ +(1) The statutory federal tax rate was 21% for the years ended December 31, 2024, 2023 and 2022. +The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2021. The earliest tax year open for examination for the State of Texas tax return is 2020. +As of December 31, 2024 and 2023, the Company had unrecognized tax benefits (“UTBs”) of $ 34.3 million and $ 35.3 million, respectively, as a result of research and experimental expenditures, which would reduce the Company’s effective tax rate in future periods if and when realized. There were no UTBs as of December 31, 2022. As of December 31, 2024 and 2023, $ 31.1 million and $ 27.0 million, respectively, of the Company’s UTBs were recorded as other long-term liabilities on the consolidated balance sheets. Although the Company does not anticipate a material change in UTBs within the next 12 months, the timing as to when the Company will substantially resolve the uncertainties associated with the UTBs is unknown. +A reconciliation of UTBs for the years ended December 31, 2024, 2023 and 2022 is as follows (in thousands). +Year Ended December 31, +2024 2023 2022 +Balance at beginning of period $ 35,336 $ — $ — +Additions for tax positions of current period 2,745 35,336 — +Adjustment for tax positions of prior periods ( 3,746 ) — — +Balance at end of period (1) +$ 34,335 $ 35,336 $ — +__________________ +(1) At December 31, 2024, the UTBs related to the U.S. federal and state of Texas jurisdictions were $ 30.2 million and $ 4.1 million, respectively. At December 31, 2023, the UTBs related to the U.S. federal and state of Texas jurisdictions were $ 30.7 million and $ 4.6 million, respectively. +NOTE 9 — STOCK-BASED COMPENSATION +In 2012, the Company’s Board adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. +In 2019, the Board adopted and shareholders approved the 2019 Incentive Plan. In 2022, the Board adopted and shareholders approved the first amendment to the 2019 Incentive Plan authorizing an additional 3,725,000 shares of common stock for issuance to employees, directors, contractors or advisors of the Company. As of December 31, 2024, the 2019 Incentive Plan provided for a maximum of 3,959,799 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future +F-34 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled. +The 2012 Incentive Plan and 2019 Incentive Plan (collectively, the “LTIPs”) are administered by the independent members of the Board, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. +During the years ended December 31, 2024, 2023 and 2022, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period. +In 2022, the Board adopted and shareholders approved an Employee Stock Purchase Plan (the “ESPP”), which authorizes a maximum of 4.0 million shares of common stock to be purchased. The purpose of the ESPP is to encourage and enable the Company’s eligible employees to acquire an interest in the Company through the ownership of common stock. At December 31, 2024, the Company had 3,891,108 remaining shares available for issuance under the ESPP. +Service-Based Restricted Stock, Restricted Stock Units and Common Stock +The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2024, 2023 and 2022 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year period. Performance-based restricted stock units granted in 2024 and 2023 vest in an amount between zero and 200 % of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2026 and 2025, respectively, as compared to a designated peer group, and will be settled in equity. +Equity-Based +A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2024 is presented below (in thousands, except fair value). +Restricted Stock Restricted Stock Units +Service Based Service Based Performance Based +Non-vested restricted stock and +restricted stock units Shares Weighted +average +fair +value Shares Weighted +average +fair +value Shares Weighted +average +fair +value +Non-vested at December 31, 2023 +596 $ 47.31 24 $ 51.50 356 $ 73.82 +Granted 383 $ 52.69 24 $ 58.90 230 $ 66.11 +Vested (1) +( 256 ) $ 44.47 ( 25 ) $ 51.60 — $ — +Forfeited ( 22 ) $ 48.53 — $ — ( 85 ) $ 71.66 +Non-vested at December 31, 2024 +701 $ 51.26 23 $ 59.21 501 $ 70.65 +__________________ +(1) On January 8, 2025 upon certification by the Board, 179,074 of the performance-based awards that were granted in 2022 vested. The vested units earned 172 % for each vested award representing 307,992 aggregate shares of common stock, which were issued on January 8, 2025. +F-35 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 9 — STOCK-BASED COMPENSATION — Continued +Liability-Based +A summary of the non-vested liability-based restricted stock units as of December 31, 2024 is presented below (in thousands). +Non-vested restricted stock units Shares +Non-vested at December 31, 2023 +465 +Granted 344 +Vested ( 223 ) +Forfeited ( 92 ) +Non-vested at December 31, 2024 +494 +During the years ended December 31, 2024, 2023 and 2022, the Company settled 222,948 , 378,852 and 587,251 liability-based awards, respectively, for $ 13.4 million, $ 20.5 million and $ 30.8 million in cash, respectively. +At December 31, 2024, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ 95.2 million, of which $ 27.4 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. +At December 31, 2024, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $ 55.9 million, of which $ 18.3 million is expected to be settled in cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.9 years. +The fair value of restricted stock and restricted stock units vested during 2024, 2023 and 2022 was $ 29.4 million, $ 64.8 million and $ 99.6 million, respectively. +Summary +During the years ended December 31, 2024, 2023 and 2022, the total expense attributable to restricted stock and restricted stock units was $ 37.3 million, $ 33.0 million and $ 51.6 million, respectively. During the years ended December 31, 2024, 2023 and 2022, the Company capitalized $ 11.8 million, $ 7.4 million and $ 5.0 million, respectively, related to stock-based compensation and expensed the remaining $ 25.5 million, $ 25.6 million and $ 47.1 million, respectively. +The total tax benefit recognized for all stock-based compensation was $ 8.0 million, $ 7.0 million and $ 11.0 million for the years ended December 31, 2024, 2023 and 2022, respectively. +NOTE 10 — EMPLOYEE BENEFIT PLANS +401(k) Plan +All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3 % of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $ 2.6 million, $ 2.2 million and $ 1.8 million in 2024, 2023 and 2022, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $ 3.3 million, $ 2.8 million and $ 2.3 million in 2024, 2023 and 2022, respectively. The Company made no additional contributions in any reporting period presented. +NOTE 11 — EQUITY +Equity Offering +On March 28, 2024, the Company completed an underwritten public offering of 5,250,000 shares of its common stock. After deducting underwriting discounts and offering expenses, the Company received net proceeds of approximately $ 342.1 million. The net proceeds from this offering were used for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement. +F-36 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 11 — EQUITY— Continued +Common Stock Dividend +The Board declared a quarterly cash dividend of $ 0.20 per share of common stock in each of the first, second and third quarters of 2024. The first quarter dividend, which totaled $ 23.9 million, was paid on March 13, 2024 to shareholders of record as of February 23, 2024. The second quarter dividend, which totaled $ 24.9 million, was paid on June 7, 2024 to shareholders of record as of May 17, 2024. The third quarter dividend, which totaled $ 24.9 million, was paid on September 5, 2024 to shareholders of record as of August 15, 2024. On October 16, 2024, the Board amended the Company’s dividend policy to increase the quarterly dividend to $ 0.25 per share of common stock for future dividend payments and also declared a quarterly cash dividend of $ 0.25 per share of common stock. The fourth quarter dividend, which totaled $ 31.3 million, was paid on December 6, 2024 to shareholders of record as of November 15, 2024. +The Board declared a quarterly cash dividend of $ 0.15 per share of common stock in each of the first three quarters of 2023 and the Board declared a quarterly cash dividend of $ 0.20 per share of common stock in the fourth quarter of 2023. +Total cash dividends declared and paid totaled $ 104.9 million and $ 77.2 million, respectively, during the years ended December 31, 2024 and 2023. +On February 18, 2025, the Board amended the Company’s dividend policy to increase the quarterly dividend to $ 0.3125 per share of common stock for future dividend payments and declared a quarterly cash dividend of $ 0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025. +Treasury Stock +On October 17, 2024, October 19, 2023 and October 20, 2022, Matador’s Board canceled all of the shares of treasury stock outstanding as of September 30, 2024, 2023 and 2022, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. +The shares of treasury stock outstanding at December 31, 2024, 2023 and 2022 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. +Preferred Stock +The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series. +San Mateo Distributions and Contributions +During the years ended December 31, 2024, 2023 and 2022, San Mateo distributed $ 321.2 million, $ 81.4 million and $ 89.5 million, respectively, to the Company and $ 97.5 million, $ 78.3 million and $ 86.0 million, respectively, to Five Point, the Company’s joint venture partner in San Mateo. +During the years ended December 31, 2024 and 2023, the Company contributed $ 19.9 million and $ 25.5 million, respectively, and Five Point contributed $ 190.6 million and $ 24.5 million, respectively, of cash to San Mateo. During the year ended December 31, 2022, neither the Company nor Five Point contributed cash to San Mateo. +San Mateo’s 2024 distributions to the Company included a special distribution of approximately $ 219.8 million, of which $ 171.5 million represented a special contribution by Five Point recorded within the Company’s statement of changes in shareholders’ equity in connection with the Pronto Transaction. San Mateo’s remaining special distribution to the Company of $ 48.3 million represented a reimbursement of certain capital expenditures for the Marlan Processing Plant expansion that were previously funded by Matador. See Note 6 for additional details. +F-37 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 11 — EQUITY— Continued +Performance Incentives +As part of the joint venture with Five Point, the Company has had the potential to earn three different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $ 73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and the Wolf portion of its West Texas asset area in Loving County over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. Through January 31, 2023, the Company had earned all of the potential $ 73.5 million in performance incentives. Five Point paid the Company $ 14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020, 2021 and 2023. Beginning in 2019, the Company had the potential to earn up to $ 150.0 million in additional performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area through mid-2024. Through September 30, 2024, the Company earned $ 108.2 million of these performance incentives. +In connection with the Pronto Transaction, the Company has the potential to earn up to $ 75.0 million in additional incentive payments from Five Point over a five-year period, of which $ 1.3 million was paid by Five Point during the fourth quarter of 2024. +During the years ended December 31, 2024 and 2023, Five Point paid the Company $ 23.8 million and $ 38.2 million, respectively, in performance incentives. These performance incentives are recorded when received, net of the $ 5.0 million and $ 8.0 million deferred tax impact to Matador for the years ended December 31, 2024 and 2023, respectively, in “Additional paid-in-capital” in the Company’s consolidated balance sheets. +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS +From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of income as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. +At December 31, 2024, the Company had various costless collar contracts open and in place to mitigate its exposure to oil price volatility, each with an established price floor and ceiling. At December 31, 2024, the Company had natural gas basis differential swap contracts open and in place to mitigate its exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. The Company had no open contracts associated with NGL prices at December 31, 2024. +The following is a summary of the Company’s open costless collar contracts at December 31, 2024. +Commodity Calculation Period Notional Quantity (Bbl) Weighted Average Price Floor +(Bbl) Weighted Average Price Ceiling +(Bbl) Fair Value of Asset (Liability) (thousands) +Oil Costless Collar 01/01/2025 - 06/30/2025 8,145,000 $ 60.00 86.26 $ 3,676 +Total open costless collar contracts $ 3,676 +F-38 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued +The following is a summary of the Company’s open basis differential swap contracts at December 31, 2024. +Notional Quantity (MMBtu) Fixed Price +($/MMBtu) Fair Value of Asset (Liability) (thousands) +Commodity Calculation Period +Natural Gas Basis Differential 01/01/2025 - 12/31/2025 10,950,000 $ ( 0.59 ) 12,292 +Total open basis differential swap contracts $ 12,292 +The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. +The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2024 and December 31, 2023 (in thousands). +Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets +December 31, 2024 +Current assets $ 19,899 $ ( 3,931 ) $ 15,968 +Current liabilities ( 3,931 ) 3,931 — +Total $ 15,968 $ — $ 15,968 +December 31, 2023 +Current assets $ 2,573 $ ( 461 ) $ 2,112 +Other assets 1,743 ( 1,185 ) 558 +Total $ 4,316 $ ( 1,646 ) $ 2,670 +The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of income for the periods presented (in thousands). +Year Ended December 31, +Type of Instrument Location in Statements of Income 2024 2023 2022 +Derivative Instrument +Oil Revenues: Realized loss on derivatives $ — $ — $ ( 75,806 ) +Natural Gas Revenues: Realized gain (loss) on derivatives 12,724 ( 9,575 ) ( 81,677 ) +Realized gain (loss) on derivatives 12,724 ( 9,575 ) ( 157,483 ) +Oil Revenues: Unrealized gain on derivatives 3,676 — 14,727 +Natural Gas Revenues: Unrealized gain (loss) on derivatives 9,623 ( 1,261 ) 4,082 +Unrealized gain (loss) on derivatives 13,299 ( 1,261 ) 18,809 +Total $ 26,023 $ ( 10,836 ) $ ( 138,674 ) +F-39 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 13 — FAIR VALUE MEASUREMENTS +The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. +Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. +Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. +Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions. +Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. +The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2024 and 2023 (in thousands). +Fair Value Measurements at +December 31, 2024 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Oil costless collars $ — $ 3,676 $ — $ 3,676 +Natural gas basis differential swaps — 12,292 — 12,292 +Total $ — $ 15,968 $ — $ 15,968 +Fair Value Measurements at +December 31, 2023 using +Description +Level 1 Level 2 Level 3 Total +Assets (Liabilities) +Natural gas basis differential swaps $ — $ 2,670 $ — $ 2,670 +Total $ — $ 2,670 $ — $ 2,670 +Additional disclosures related to derivative financial instruments are provided in Note 12. +Other Fair Value Measurements +At December 31, 2024 and 2023, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities. +At December 31, 2024 and 2023, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy. +At December 31, 2024 and 2023, the fair value of the 2028 Notes was $ 505.4 million and $ 510.9 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +At December 31, 2024, the fair value of the 2032 Notes was $ 890.7 million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +F-40 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 13 — FAIR VALUE MEASUREMENTS — Continued +At December 31, 2024, the fair value of the 2033 Notes was $ 730.6 million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy. +Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2024 and 2023. +NOTE 14 — COMMITMENTS AND CONTINGENCIES +Processing, Transportation and Produced Water Disposal Commitments +Firm Commitments +From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $ 68.3 million and $ 51.5 million for deliveries under these agreements during the years ended December 31, 2024 and 2023, respectively. Certain of these agreements contain minimum volume commitments, including certain agreements with Northwind that were entered into in connection with the Pronto Transaction in 2024. See Note 6 for additional details. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2024, the total deficiencies required to be paid by the Company under these agreements would be approximately $ 692.6 million. +San Mateo Commitments +The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15 -year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15 -year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments, including certain agreements with Pronto that were entered into in connection with the Pronto Transaction in 2024. See Note 6 for additional details. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2024 was approximately $ 804.3 million. +Other Commitments +The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $ 20.4 million at December 31, 2024. +At December 31, 2024, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $ 60.8 million at December 31, 2024. The Company expects these costs to be incurred within the next year. +At December 31, 2024, San Mateo had outstanding midstream commitments of $ 67.7 million for the construction and installation of the Marlan Processing Plant expansion with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities. The Company expects the majority of these costs to be incurred within the next year. +Legal Proceedings +The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote +F-41 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 14 — COMMITMENTS AND CONTINGENCIES — Continued +that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. +NOTE 15 — SUPPLEMENTAL DISCLOSURES +Accrued Liabilities +The following table summarizes the Company’s current accrued liabilities at December 31, 2024 and 2023 (in thousands). +December 31, +2024 2023 +Accrued evaluated and unproved and unevaluated property costs $ 197,817 $ 144,443 +Accrued midstream properties costs 31,595 55,195 +Accrued lease operating expenses 92,364 62,005 +Accrued interest on debt 34,769 22,857 +Accrued asset retirement obligations 8,431 4,605 +Accrued partners’ share of joint interest charges 41,614 42,101 +Accrued payable related to purchased natural gas 9,063 10,400 +Other 25,831 24,242 +Total accrued liabilities $ 441,484 $ 365,848 +Supplemental Cash Flow Information +The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2024, 2023 and 2022 (in thousands). +Year Ended December 31, +2024 2023 2022 +Cash paid for income taxes, net of refunds received (1) +$ 30,004 $ 4,597 $ 63,500 +Cash paid for interest expense, net of amounts capitalized $ 160,273 $ 111,742 $ 72,561 +Increase in asset retirement obligations related to mineral properties $ 23,773 $ 33,209 $ 9,111 +Increase in asset retirement obligations related to midstream properties $ 777 $ 1,197 $ 251 +Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures $ 79,363 $ 31,364 $ ( 13,304 ) +Increase (decrease) in liabilities for acquisition of oil and natural gas properties $ 212 $ 709 $ ( 2,531 ) +(Decrease) increase in liabilities for midstream capital expenditures $ ( 23,789 ) $ 43,572 $ 3,824 +Stock-based compensation expense recognized as liability $ 13,565 $ 11,380 $ 31,906 +Transfer of inventory (to) from oil and natural gas properties $ ( 14,904 ) $ 933 $ 148 +_____________________ +(1) Represents tax payments of $ 34.4 million, $ 13.5 million and $ 63.5 million for the years ended December 31, 2024, 2023 and 2022, respectively. +The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands). +Year Ended December 31, +2024 2023 2022 +Cash $ 23,033 $ 52,662 $ 505,179 +Restricted cash 71,709 53,636 42,151 +Total cash and restricted cash $ 94,742 $ 106,298 $ 547,330 +F-42 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 16 — SEGMENT INFORMATION +The Company has two reportable business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of, and provides flow assurance for, the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. The majority of the Company’s midstream operations in the Delaware Basin are conducted through San Mateo. +The Company’s chief operating decision maker (“CODM”) is the Chairman and Chief Executive Officer. The CODM uses operating income to assess income generated from each segment to allocate resources by either reinvesting profits as midstream or drilling and completion capital expenditures, or for determining the appropriate amounts for acquisition spend, the repayment of debt and the payment of dividends. +The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2024 +Oil and natural gas revenues $ 3,129,598 $ 14,236 $ — $ — $ 3,143,834 +Midstream services revenues — 453,464 — ( 312,437 ) 141,027 +Sales of purchased natural gas 22,186 171,911 — — 194,097 +Realized gain on derivatives 12,724 — — — 12,724 +Unrealized gain on derivatives 13,299 — — — 13,299 +Operating expense (1) +504,906 171,492 — ( 163,362 ) 513,036 +Other expenses (2) +1,370,422 222,126 113,774 ( 149,075 ) 1,557,247 +Operating income (3) +$ 1,302,479 $ 245,993 $ ( 113,774 ) $ — $ 1,434,698 +Total assets (4) +$ 9,117,095 $ 1,613,936 $ 119,078 $ — $ 10,850,109 +Capital expenditures (5) +$ 3,396,543 $ 504,315 $ 5,691 $ — $ 3,906,549 +_____________________ +(1) Operating expense includes lease operating expense for the exploration and production segment and plant and other midstream operating expense for the midstream segment. +(2) Includes depletion, depreciation and amortization expenses of $ 929.0 million and $ 43.9 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 1.4 million. Other expenses for each reportable segment also includes (i) production taxes, transportation and processing, (ii) general and administrative expenses, (iii) accretion of asset retirement obligations and (iv) purchased natural gas. +(3) Includes $ 86.0 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(4) Excludes intercompany receivables and investments in subsidiaries. +(5) Includes $ 2.08 billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ 236.2 million in midstream acquisition expenditures and $ 29.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-43 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2023 +Oil and natural gas revenues $ 2,538,813 $ 6,786 $ — $ — $ 2,545,599 +Midstream services revenues — 346,933 — ( 224,780 ) 122,153 +Sales of purchased natural gas 23,521 126,348 — — 149,869 +Realized loss on derivatives ( 9,575 ) — — — ( 9,575 ) +Unrealized loss on derivatives ( 1,261 ) — — — ( 1,261 ) +Operating expense (1) +358,789 128,910 — ( 115,134 ) 372,565 +Other expenses (2) +1,059,168 176,014 99,362 ( 109,646 ) 1,224,898 +Operating income (3) +$ 1,133,541 $ 175,143 $ ( 99,362 ) $ — $ 1,209,322 +Total assets (4) +$ 6,385,762 $ 1,257,988 $ 83,246 $ — $ 7,726,996 +Capital expenditures (5) +$ 2,970,230 $ 254,393 $ 3,636 $ — $ 3,228,259 +_____________________ +(1) Operating expense includes lease operating expense for the exploration and production segment and plant and other midstream operating expense for the midstream segment. +(2) Includes depletion, depreciation and amortization expenses of $ 675.0 million and $ 40.4 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 1.3 million. Other expenses for each reportable segment also includes (i) production taxes, transportation and processing, (ii) general and administrative expenses, (iii) accretion of asset retirement obligations and (iv) purchased natural gas. +(3) Includes $ 64.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(4) Excludes intercompany receivables and investments in subsidiaries. +(5) Includes $ 1.81 billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ 63.6 million in midstream acquisition expenditures and $ 42.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-44 +Table of Contents +Matador Resources Company and Subsidiaries +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED +December 31, 2024, 2023 and 2022 +NOTE 16 — SEGMENT INFORMATION — Continued +Exploration and Production Consolidations and Eliminations Consolidated Company +Midstream Corporate +Year Ended December 31, 2022 +Oil and natural gas revenues $ 2,897,336 $ 8,402 $ — $ — $ 2,905,738 +Midstream services revenues — 298,184 — ( 207,578 ) 90,606 +Sales of purchased natural gas 116,772 83,583 — — 200,355 +Realized loss on derivatives ( 157,483 ) — — — ( 157,483 ) +Unrealized gain on derivatives 18,809 — — — 18,809 +Operating expense (1) +261,776 95,522 — ( 104,671 ) 252,627 +Other expenses (2) +915,328 132,034 101,673 ( 102,907 ) 1,046,128 +Operating income (3) +$ 1,698,330 $ 162,613 $ ( 101,673 ) $ — $ 1,759,270 +Total assets (4) +$ 4,022,609 $ 1,016,580 $ 515,316 $ — $ 5,554,505 +Capital expenditures (5) +$ 903,518 $ 158,544 $ 1,213 $ — $ 1,063,275 +_____________________ +(1) Operating expense includes lease operating expense for the exploration and production segment and plant and other midstream operating expense for the midstream segment. +(2) Includes depletion, depreciation and amortization expenses of $ 429.7 million and $ 34.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 2.0 million. Other expenses for each reportable segment also includes (i) production taxes, transportation and processing, (ii) general and administrative expenses, (iii) accretion of asset retirement obligations and (iv) purchased natural gas. +(3) Includes $ 72.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. +(4) Excludes intercompany receivables and investments in subsidiaries. +(5) Includes $ 131.0 million attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ 75.8 million in midstream acquisition expenditures and $ 39.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. +F-45 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION +December 31, 2024, 2023 and 2022 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES +Costs Incurred +The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2024, 2023 and 2022 (in thousands). +Year Ended December 31, +2024 2023 2022 +Property acquisition costs +Proved $ 1,488,033 $ 1,478,258 $ 36,985 +Unproved and unevaluated 575,046 328,579 97,127 +Exploration costs 71,381 230,712 136,209 +Development costs 1,287,221 966,338 643,947 +Total costs incurred (1) +$ 3,421,681 $ 3,003,887 $ 914,268 +__________________ +(1) Excludes midstream-related development and corporate costs of approximately $510.0 million, $258.0 million and $159.8 million for the years ended December 31, 2024, 2023 and 2022, respectively. +Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the year ended December 31, 2024, a majority of the Company’s property acquisition costs resulted from the Ameredev Acquisition. For the year ended December 31, 2023, a majority of the Company’s property acquisition costs resulted from the Advance Acquisition. +Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the year ended December 31, 2024, the Company capitalized $11.3 million of geological and geophysical costs, which are included as exploration costs in the table above. The Company did not capitalize any geological and geophysical costs in 2023 or 2022. +Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, completing and equipping development wells and acquiring, constructing and installing production facilities. +Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were an increase of $25.1 million, an increase of $33.8 million and an increase of $10.7 million for the years ended December 31, 2024, 2023 and 2022, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $66.6 million, $54.2 million and $47.8 million of these internal costs for the years ended December 31, 2024, 2023 and 2022, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $17.5 million, $20.2 million and $10.1 million of its interest expense for the years ended December 31, 2024, 2023 and 2022, respectively, excluding midstream-related capitalized interest expense. +Oil and Natural Gas Reserves +Proved reserves are the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including assumptions related to oil and natural gas prices, drilling, completion and operating expenses, capital expenditures, taxes and +F-46 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2024, 2023 and 2022 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. +The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where +the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2024, 2023 and 2022 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. +Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2024, these average oil and natural gas prices were $71.96 per Bbl and $2.13 per MMBtu, respectively. For the period from January through December 2023, these average oil and natural gas prices were $74.70 per Bbl and $2.64 per MMBtu, respectively. For the period from January through December 2022, these average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. +F-47 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2024, 2023 and 2022 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. +Net Proved Reserves +Oil Natural Gas Oil +Equivalent +(MBbl) (MMcf) (MBOE) +Total at December 31, 2021 +181,306 852,547 323,397 +Revisions of prior estimates (6,953) (4,324) (7,673) +Net acquisitions (divestitures) of minerals-in-place 1,239 (1,332) 1,017 +Extensions and discoveries 42,640 215,011 78,476 +Production (21,943) (99,308) (38,495) +Total at December 31, 2022 +196,289 962,594 356,722 +Revisions of prior estimates (31,184) (88,779) (45,981) +Net acquisitions of minerals-in-place 78,550 183,311 109,102 +Extensions and discoveries 56,164 193,054 88,339 +Production (27,542) (123,420) (48,112) +Total at December 31, 2023 +272,277 1,126,760 460,070 +Revisions of prior estimates (11,264) 32,640 (5,824) +Net acquisitions of minerals-in-place 73,347 279,170 119,875 +Extensions and discoveries 64,012 215,389 99,910 +Production (36,530) (155,790) (62,495) +Total at December 31, 2024 +361,842 1,498,169 611,536 +Proved Developed Reserves +December 31, 2021 102,233 546,173 193,262 +December 31, 2022 116,030 632,858 221,507 +December 31, 2023 161,642 782,733 292,097 +December 31, 2024 206,269 963,170 366,797 +Proved Undeveloped Reserves +December 31, 2021 79,073 306,374 130,135 +December 31, 2022 80,259 329,736 135,215 +December 31, 2023 110,635 344,026 167,973 +December 31, 2024 155,573 534,999 244,740 +The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2024, 2023 and 2022. +The Company’s proved oil and natural gas reserves increased 33% from 460.1 million BOE at December 31, 2023 to 611.5 million BOE at December 31, 2024. The Company’s proved oil and natural gas reserves increased by 214.0 million BOE and the Company produced 62.5 million BOE during the year ended December 31, 2024, resulting in a net increase of 151.5 million BOE. This increase in proved oil and natural gas reserves was primarily attributable to the Ameredev Acquisition and the Company’s delineation and development operations in the Delaware Basin during 2024. The Company increased its total proved oil and natural gas reserves by 119.9 million BOE as a result of acquisitions and trades during 2024. The Company also added 99.9 million BOE in proved reserves through extensions and discoveries during 2024, of which 28.4 million BOE resulted from new well locations turned to sales during 2024 to establish proved developed reserves and 71.5 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2024. These increases were partially offset by net downward revisions of prior estimates +F-48 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2024, 2023 and 2022 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +for proved oil and natural gas reserves, which primarily included the removal of 8.2 million BOE resulting from the 4% decrease in oil prices and the 19% decrease in natural gas prices used to estimate total proved reserves at December 31, 2024, as compared to December 31, 2023, and 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the Company’s properties in the Delaware Basin. As the Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 15.3 million BOE to proved reserves at a future date. These downward revisions at December 31, 2024 were partially offset by positive forecast updates of 21.7 million BOE. +The Company’s proved developed oil and natural gas reserves increased 26% from 292.1 million BOE at December 31, 2023 to 366.8 million BOE at December 31, 2024. The Company’s proved developed oil and natural gas reserves increased by 137.2 million BOE and the Company produced 62.5 million BOE during the year ended December 31, 2024, resulting in a net increase of 74.7 million BOE. The Company added 28.4 million BOE in proved developed reserves through extensions and discoveries during 2024, which resulted from new well locations drilled during 2024 to establish proved reserves. In addition, during 2024 the Company converted 54.6 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin. The Company also increased its proved developed reserves by 59.3 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. Additionally, the Company realized approximately 5.1 million BOE in net downward revisions of prior estimates in 2024, most of which was attributable to the lower commodity prices used to estimate proved reserves at December 31, 2024, which resulted in shorter estimated economic lives for certain of its producing properties. +The Company’s proved undeveloped oil and natural gas reserves increased 46% from 168.0 million BOE at December 31, 2023 to 244.7 million at December 31, 2024. The Company added 71.5 million BOE in proved undeveloped reserves through extensions and discoveries during 2024, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2024. In addition, the Company increased its proved undeveloped reserves by 60.6 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. These increases were partially offset by net downward revisions of prior estimates of proved undeveloped reserves, including the removal of 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the properties in the Delaware Basin and the removal of 2.1 million BOE for certain expense and pricing updates. These downward revisions were largely offset by positive forecast updates of 16.3 million BOE. +At December 31, 2024, the Company’s proved reserves were comprised of 59% oil and 41% natural gas and were approximately 60% proved developed and 40% proved undeveloped. The decrease in the Company’s proved developed reserves as a percentage of its total proved reserves at December 31, 2024, as compared to 63% and 62% proved developed reserves at December 31, 2023 and 2022, respectively, was primarily a result of extensions and discoveries of new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin and the Ameredev Acquisition. +The Company’s proved oil and natural gas reserves increased 29% from 356.7 million BOE at December 31, 2022 to 460.1 million BOE at December 31, 2023. The Company’s proved oil and natural gas reserves increased by 151.5 million BOE and the Company produced 48.1 million BOE during the year ended December 31, 2023, resulting in a net increase of 103.3 million BOE. This increase in proved oil and natural gas reserves was primarily attributable to the Advance Acquisition and the Company’s delineation and development operations in the Delaware Basin during 2023. The Company increased its total proved oil and natural gas reserves by 109.1 million BOE as a result of acquisitions and trades during 2023. The Company also added 88.3 million BOE in proved reserves through extensions and discoveries during 2023, of which 27.6 million BOE resulted from new well locations drilled during 2023 to establish proved developed reserves and 60.7 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2023. These increases were partially offset by the removal of 17.4 million BOE resulting from the 17% decrease in oil prices and the 58% decrease in natural gas prices used to estimate total proved reserves at December 31, 2023, as compared to December 31, 2022, and the removal of 31.5 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the Company’s properties in the Delaware Basin. +The Company’s proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. The Company’s proved oil and natural gas reserves increased by 71.8 million BOE and the Company produced 38.5 million BOE during the year ended December 31, 2022, resulting in a net increase of 33.3 +F-49 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2024, 2023 and 2022 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +million BOE. The Company added 78.5 million BOE in proved reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations drilled during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2022. The Company realized approximately 7.7 million BOE in net downward revisions of prior estimates in 2022, due primarily to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking as a result of changes in development plans for certain of the properties in the Delaware Basin at December 31, 2022. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves +The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. +As noted previously, for the period from January through December 2024, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $71.96 per Bbl and $2.13 per MMBtu, respectively. For the period from January through December 2023, the comparable average oil and natural gas prices were $74.70 per Bbl and $2.64 per MMBtu, respectively. For the period from January through December 2022, the comparable average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. +Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production, development and plugging and abandonment costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. +Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. +The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2024, 2023 and 2022 (in thousands). +Year Ended December 31, +2024 2023 2022 +Future cash inflows $ 29,033,021 $ 23,662,653 $ 24,952,118 +Future production costs (10,284,800) (7,717,106) (6,752,752) +Future development costs (2,705,340) (2,162,625) (1,776,029) +Future income tax expense (3,326,489) (2,939,514) (3,935,271) +Future net cash flows 12,716,392 10,843,408 12,488,066 +10% annual discount for estimated timing of cash flows (5,339,842) (4,729,916) (5,504,863) +Standardized measure of discounted future net cash flows $ 7,376,550 $ 6,113,492 $ 6,983,203 +F-50 +Table of Contents +Matador Resources Company and Subsidiaries +UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED +December 31, 2024, 2023 and 2022 +SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued +The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2024, 2023 and 2022 (in thousands). +Year Ended December 31, +2024 2023 2022 +Balance, beginning of period $ 6,113,492 $ 6,983,203 $ 4,375,425 +Net change in sales and transfer prices and in production (lifting) costs related to future production (915,645) (3,074,085) 4,046,504 +Changes in estimated future development costs (706,728) (504,323) (744,687) +Sales and transfers of oil and natural gas produced during the period (2,496,524) (2,037,451) (2,466,440) +Net purchases of reserves in place 2,310,776 2,113,620 28,841 +Net change due to extensions and discoveries 1,925,926 1,711,389 2,017,170 +Net change due to revisions in estimates of reserves quantities (102,776) (890,794) (8,576) +Previously estimated development costs incurred during the period 685,163 441,671 434,336 +Accretion of discount 770,407 807,896 475,474 +Other 15,190 3,913 1,982 +Net change in income taxes (222,731) 558,453 (1,176,826) +Standardized measure of discounted future net cash flows $ 7,376,550 $ 6,113,492 $ 6,983,203 +F-51 \ No newline at end of file diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/filing_metadata.csv b/raw/filings/0001520006/2024/0001520006-25-000066/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..4155ff4d90bcfcd4d7bdb4c904133ffcb3164e76 --- /dev/null +++ b/raw/filings/0001520006/2024/0001520006-25-000066/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001520006,MTDR,Matador Resources Co,10-K,2025-02-25,2024-12-31,2025-02-26T02:41:54.000Z,0001520006-25-000066,mtdr-20241231.htm,10-K,15363210,1,1,https://www.sec.gov/Archives/edgar/data/1520006/000152000625000066/mtdr-20241231.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000625000066/,2024,2024,1 diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/item1.txt b/raw/filings/0001520006/2024/0001520006-25-000066/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..5504f2559eb4b60421ea4845acd570b838265a74 --- /dev/null +++ b/raw/filings/0001520006/2024/0001520006-25-000066/item1.txt @@ -0,0 +1,625 @@ +Item 1. Business. +In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Ameredev” refer to Ameredev Stateline II, LLC, (iv) references to “Piñon” refer to Piñon Midstream, LLC, (v) references to the “Ameredev Acquisition” refer to the acquisition of Ameredev from affiliates of EnCap Investments L.P., including (a) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (b) an approximate 19% stake in the parent company of Piñon, which was completed by a subsidiary of the Company on September 18, 2024, (vi) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (vii) references to the “Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, and the acquisition of additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico on December 1, 2023, (viii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries (including, as of December 18, 2024, Pronto), and (ix) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report. +General +We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million. +2 +Table of Contents +On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. +Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: +• focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; +• identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; +• continue to improve operational and cost efficiencies; +• identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Matador; +• maintain our financial discipline; +• return capital to shareholders through our dividend policy; +• pursue opportunistic acquisitions, divestitures and joint ventures; and +• provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices. +The successful execution of our business strategies, including the Ameredev Acquisition, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2024. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down a portion of the borrowings that funded the Advance Acquisition and Ameredev Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC or its affiliates (“Five Point”), our joint venture partner in San Mateo. Further, we completed several important financing transactions in 2024, including the Pronto Transaction, the 2024 Equity Offering, the 2026 Notes Repurchase, the 2032 Notes Offering and the 2033 Notes Offering, twice increasing the elected borrowing commitment and the borrowing base under our Credit Agreement and increasing the lender commitments under the San Mateo Credit Facility (all as defined below). San Mateo also achieved important milestones in 2024, including completing the natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024. +2024 Highlights +Ameredev Acquisition +On September 18, 2024, our wholly-owned subsidiary completed the acquisition of Ameredev from affiliates of EnCap +Investments L.P., including (i) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (ii) an approximate 19% stake in the parent company of Piñon. The Ameredev Acquisition had an effective date of June 1, 2024 and an aggregate as-adjusted closing purchase price of approximately $1.83 billion in cash, which amount is subject to customary post-closing adjustments. The purchase price for the Ameredev Acquisition was funded by a combination of cash on hand and borrowings under our existing secured revolving credit facility (the “Credit Agreement”), which was amended on September 18, 2024 to, among other things: (i) provide for a term loan of $250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitments under the revolving credit facility from $1.50 billion to $2.25 billion. On September 25, 2024, we completed the sale of $750.0 million in aggregate principal amount of our 6.25% senior unsecured notes due 2033 (the “2033 Notes”) and used the net proceeds to partially repay borrowings outstanding under our Credit Agreement, including all of the $250.0 million in outstanding borrowings under the term loan. On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. We received $113.6 million from the sale of Piñon during the fourth quarter of 2024 and used these proceeds to reduce borrowings under our Credit Agreement. We currently expect to receive an additional $4.8 million from the sale of Piñon in the first half of 2025. +3 +Table of Contents +The results of operations for the Ameredev Acquisition since the closing date of September 18, 2024 have been included in our consolidated financial statements for the year ended December 31, 2024. The oil and natural gas production from the Ameredev Acquisition increased our revenues and net income for the period from September 18, 2024 through December 31, 2024 by $118.0 million and $34.8 million, respectively. See Note 6 to the consolidated financial statements in this Annual Report for more information regarding the Ameredev Acquisition. Such information is incorporated herein by reference. +Increased Oil, Natural Gas and Oil Equivalent Production +For the year ended December 31, 2024, we achieved record oil, natural gas and average daily oil equivalent production. In 2024, we produced 36.5 million Bbl of oil, an increase of 33%, as compared to 27.5 million Bbl of oil produced in 2023. We also produced 155.8 Bcf of natural gas, an increase of 26% from 123.4 Bcf of natural gas produced in 2023. Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023. The increase in oil and natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin throughout 2024, which offset declining production in the Eagle Ford shale and Northwest Louisiana. Oil production comprised 58% and 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the years ended December 31, 2024 and 2023, respectively. +Increased Oil, Natural Gas and Oil Equivalent Reserves +At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, an increase of 33% from 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, at December 31, 2023. The Standardized Measure of our total proved oil and natural gas reserves increased 21% from $6.11 billion at December 31, 2023 to $7.38 billion at December 31, 2024. The PV-10 of our total proved oil and natural gas reserves increased 20% from $7.70 billion at December 31, 2023 to $9.23 billion at December 31, 2024. The increases in our Standardized Measure and PV-10 were primarily a result of a 33% increase in our total proved oil and natural gas reserves at December 31, 2024, as compared to December 31, 2023, partially offset by the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2024, as compared to December 31, 2023. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” +At December 31, 2024, estimated proved developed reserves included 206.3 million Bbl of oil and 963.2 Bcf of natural gas, and estimated proved undeveloped reserves included 155.6 million Bbl of oil and 535.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 60% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2024. Proved developed reserves and proved oil reserves comprised 63% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2023. +Operational Highlights +We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2025. +We completed and began producing oil and natural gas from 251 gross (110.2 net) horizontal wells in the Delaware Basin in 2024, including 124 gross (101.9 net) operated and 127 gross (8.3 net) non-operated wells. At December 31, 2024, our total acreage position in the Delaware Basin was approximately 328,000 gross (198,700 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving, Ward and Winkler Counties, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving, Ward and Winkler Counties, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 31% to 166,273 BOE per day (97% of total oil equivalent production), including 99,086 Bbl of oil per day (99% of total oil production) and 403.1 MMcf of natural gas per day (95% of total natural gas production), in 2024, as compared to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023. We expect our Delaware Basin production to increase in 2025 as we continue the delineation and development of these asset areas. +4 +Table of Contents +During 2024, we achieved several operational milestones in the Delaware Basin. These milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales: +• 21 Antelope Ridge wells on properties acquired in the Advance Acquisition in the first half of 2024, which matched the largest single batch development project in our history; +• Five U-Turn wells in the second half of 2024, with significantly reduced drilling time as compared to our initial U-Turn wells that we turned to sales in 2023; and +• increased efficiencies and capital savings through the introduction of Trimul-Frac and continued use of Simul-Frac. +In addition to achieving these key operational milestones, other operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2024 included: +• continued drilling of longer laterals, with average completed lateral length for operated wells turned to sales in 2024 of approximately 9,300 feet; and +• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2024 of $1.32 billion, which was within our estimated range for 2024 D/C/E capital expenditures of $1.15 to $1.35 billion, as provided on October 22, 2024. +Capital Resources and Financing Highlights +During 2024, we achieved several significant and important capital resources objectives, which included: +• the generation of free cash flow in all four quarters of 2024; +• the amendment of our dividend policy in the fourth quarter of 2024, pursuant to which we increased the quarterly cash dividend from $0.20 per share of common stock to $0.25 per share of common stock; +• the receipt of $219.8 million in special distributions from San Mateo as a result of the Pronto Transaction; and +• the receipt of $23.8 million in performance incentives directly from Five Point. +In addition, we completed several financing transactions in 2024 that increased our operational flexibility, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included: +• the underwritten public offering of 5,250,000 shares of our common stock (the “2024 Equity Offering”); +• the repurchase of all of the aggregate principal amount of approximately $699.2 million of outstanding senior notes due 2026 (the “2026 Notes”) through our cash tender offer and subsequent exercise of our optional redemption right in April 2024 (the “2026 Notes Repurchase”); +• the issuance of $900.0 million in aggregate principal amount of 6.50% senior notes due 2032 (the “2032 Notes”, and such issuance, the “2032 Notes Offering”); +• the issuance of $750.0 million in aggregate principal amount of 2033 Notes (the “2033 Notes Offering”); +• the spring and fall redeterminations under, and amendments of, our Credit Agreement to collectively (i) increase the borrowing base to $3.25 billion, as compared to $2.50 billion at December 31, 2023, (ii) increase the elected borrowing commitment to $2.25 billion, as compared to $1.325 billion at December 31, 2023, (iii) increase the maximum facility amount to $3.50 billion, as compared to $2.00 billion at December 31, 2023, (iv) extend the maturity date from October 31, 2026 to March 22, 2029 and (v) add five new banks to our lending group; and +• the amendment of San Mateo’s secured revolving credit facility (the “San Mateo Credit Facility”) in November 2024 to (i) increase the lender commitments from $535.0 million to $800.0 million, (ii) extend the maturity date from December 9, 2026 to November 26, 2029 and (iii) add six new banks to San Mateo’s lending group. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions. +Midstream Highlights +Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point. +5 +Table of Contents +On December 18, 2024, we completed a transaction with Five Point in which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million (the “Pronto Transaction”). In connection with the Pronto Transaction, we received a special distribution from San Mateo of approximately $219.8 million. In addition, we have the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by us and 49% by Five Point. +Pronto owns and operates the Marlan cryogenic natural gas processing plant (the “Marlan Processing Plant”), which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. Pronto also owns and operates five compressor stations and approximately 120 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +In connection with the Pronto Transaction, Matador dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind Midstream Partners LLC (“Northwind”), an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing. +San Mateo achieved strong operating results in 2024, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. +In March 2024, we completed our natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024. +During 2024, San Mateo and Pronto also closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin. +At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included: +• Natural Gas Assets : 520 MMcf per day of designed natural gas cryogenic processing capacity and approximately 295 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); +• Oil Assets : three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 110 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and +• Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. +On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of gas gathering, water gathering and oil transportation and gathering pipeline assets. +Environmental, Social and Governance (“ESG”) Initiatives +We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and highest applicable regulatory and legal standards. We also report on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB). +Highlights from our ESG initiatives, which generally relate to our operations in 2023 except as otherwise noted, include: +6 +Table of Contents +• decreased Exploration and Production direct greenhouse gas emissions intensity by 58% in 2023, as compared to 2019; +• decreased methane emissions intensity by 76% in 2023, as compared to 2019; +• decreased flaring intensity by 82% in 2023, as compared to 2019; +• utilized non-fresh water in 97% of total water consumption in 2023; +• increased number of wells utilizing recycled produced water to 89% of total wells completed in 2023, as compared to 72% in 2022; +• transported 99% of operated produced water and 96% of operated produced oil by pipeline in 2024; and +• provided approximately 22,500 hours of employee continuing education, equating to approximately 50 hours per employee in 2024. +The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2024 data from our ESG initiatives in the second half of 2025 in connection with the preparation of our 2024 Sustainability Report. +Exploration and Production Segment +Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2024, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. +The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2024. +Producing Total Identified Estimated Net Proved +Wells +Drilling Locations (1) +Reserves (2) +Avg. Daily +Gross Net Gross Net Gross Net % Production +Acreage Acreage +MBOE (3) +Developed +(BOE/d) (3) +Southeast New Mexico/West Texas: +Delaware Basin (4) +328,000 198,700 1,949 1,019.8 5,080 1,869 606,196 59.7 166,273 +South Texas: +Eagle Ford (5) +2,900 2,900 31 30.3 6 4 1,667 58.8 986 +Northwest Louisiana +Haynesville 16,200 8,900 268 18.5 131 13 3,286 100.0 2,859 +Cotton Valley (6) +15,700 14,800 66 39.0 144 37 387 100.0 633 +Area Total (7) +18,500 17,300 334 57.5 275 50 3,673 100.0 3,492 +Total 349,400 218,900 2,314 1,107.6 5,361 1,923 611,536 60.0 170,751 +__________________ +(1) Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2024. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2024, approximately 77% of these identified drilling locations in the Delaware Basin were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 89% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2024, these engineered drilling locations included 439 gross (258 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon formations, in the Delaware Basin. At December 31, 2024, we had assigned no proved undeveloped reserves to our leasehold in Northwest Louisiana. +(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference. +(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Yeso and Avalon plays on our acreage in the Delaware Basin at December 31, 2024. +7 +Table of Contents +(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(6) Includes the Cotton Valley formation and shallower zones. +(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations. +We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2024, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2024, we also operated approximately 100% of our Eagle Ford acreage and approximately 51% of our Northwest Louisiana acreage. +While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. +Southeast New Mexico and West Texas — Delaware Basin +The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin had focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology has enhanced the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations. +In the western part of the Permian Basin, also known as the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D. +At December 31, 2024, our total acreage position in Southeast New Mexico and West Texas was approximately 328,000 gross (198,700 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving, Ward and Winkler Counties, Texas. These acreage totals included approximately 73,700 gross (42,100 net) acres in our Ranger asset area in Lea County, 59,600 gross (24,000 net) acres in our Arrowhead asset area in Eddy County, 47,000 gross (26,500 net) acres in our Rustler Breaks asset area in Eddy County, 63,800 gross (50,400 net) acres in our Antelope Ridge asset area in Lea County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County, 47,300 gross (30,000 net) acres in our Twin Lakes asset area in Lea County and 33,200 gross (22,300 net) acres in our West Texas asset area in Loving, Ward and Winkler Counties at December 31, 2024. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka, Yeso and Morrow formations. At December 31, 2024, our acreage position in the Delaware Basin was approximately 79% held by existing production. Excluding the Twin Lakes asset area, our acreage position in the Delaware Basin was approximately 88% held by existing production at December 31, 2024. +During the year ended December 31, 2024, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 251 gross (110.2 net) horizontal wells in the Delaware Basin, including 124 gross (101.9 net) operated horizontal wells and 127 gross (8.3 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2024, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow. +As a result of our ongoing drilling and completion operations in these asset areas and the Ameredev Acquisition, our Delaware Basin production increased significantly in 2024. Our average daily oil equivalent production from the Delaware Basin increased approximately 31% to 166,273 BOE per day (97% of total oil equivalent production), including 99,086 Bbl of oil per day (99% of total oil production) and 403.1 MMcf of natural gas per day (95% of total natural gas production), in 2024, +8 +Table of Contents +as compared to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023. +At December 31, 2024, approximately 99% of our estimated total proved oil and natural gas reserves, or 606.2 million BOE, was attributable to the Delaware Basin, including approximately 360.4 million Bbl of oil and 1.47 Tcf of natural gas, a 34% increase, as compared to 452.6 million BOE for the year ended December 31, 2023. Our Delaware Basin proved reserves at December 31, 2024 comprised approximately 100% of our proved oil reserves and 98% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 97% of our proved natural gas reserves at December 31, 2023. +At December 31, 2024, we had identified 5,080 gross (1,869 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon, Yeso and Avalon formations. At December 31, 2024, these locations had a total net lateral length of approximately 18.3 million feet, or 3,680 miles, an increase of 22% as compared to the total net lateral length of approximately 15.0 million feet, or 2,975 miles, as of December 31, 2023. These locations include 2,546 gross (1,667 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2024, approximately 77% of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 89% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2024, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2024, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2024, these potential future drilling locations included 439 gross (258 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon and Avalon, to which we have assigned proved undeveloped reserves. +We began 2024 o perating seven drilling rigs in the Delaware Basin. We added an eighth operated drilling rig in the first quarter of 2024 and a ninth operated drilling rig late in the second quarter of 2024. Upon the consummation of the Ameredev Acquisition, we continued operating a total of nine drilling rigs for the combined Matador and Ameredev properties. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. +Antelope Ridge Asset Area - Lea County, New Mexico +In the Antelope Ridge asset area, we turned to sales 60 gross (52.2 net) operated wells and 14 gross (0.9 net) non-operated wells during 2024. +In the second quarter of 2024, we achieved an operational milestone when we turned to sales 21 gross (18.9 net) wells in the Antelope Ridge asset area that were acquired as part of the Advance Acquisition. Each of these wells had a lateral length of 1.5 miles, resulting in approximately 155,000 completed lateral feet. These wells included three First Bone Spring, six Second Bone Spring, three Third Bone Spring, six Third Bone Spring Carbonate, and three Wolfcamp A-XY completions, which averaged 24-hour initial production tests of 1,728 BOE per day with oil cuts averaging 83% and have in aggregate produced 4.2 million BOE in approximately eight months of production. +We turned to sales an additional 39 gross (33.3 net) operated wells in the Antelope Ridge asset area at various times during 2024. In total, these 39 Antelope Ridge wells, which included eight First Bone Spring, 12 Second Bone Spring, seven Third Bone Spring, four Third Bone Spring Carbonate, three Wolfcamp A-XY, two Wolfcamp A, two Wolfcamp B and one Wolfcamp D completions, have produced in aggregate approximately 2.4 million BOE in an average of approximately three months of production. These 39 wells had average completed lateral lengths of approximately 9,500 feet. +Stateline Asset Area - Eddy County, New Mexico +We turned to sales six gross (6.0 net) operated wells in the Stateline asset area during 2024. These wells, which included four Upper Avalon and two Lower Avalon completions, have produced in aggregate approximately 0.4 million BOE in approximately seven months of production. These six wells had average completed lateral lengths of approximately 12,100 feet. +We also turned to sales 18 gross (0.4 net) non-operated wells in the Stateline asset area during 2024. +9 +Table of Contents +Ranger and Twin Lakes Asset Areas - Lea County, New Mexico +In the Ranger asset area, we turned to sales ten gross (7.9 net) operated wells and 14 gross (1.9 net) non-operated wells during 2024. In the Twin Lakes asset area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2024. +In total, these ten Ranger operated wells, which included four First Bone Spring, four Second Bone Spring, one Third Bone Spring and one Avalon completions, have produced in aggregate approximately 1.5 million BOE in an average of approximately eight months of production. These ten wells had average completed lateral lengths of approximately 10,100 feet. +Arrowhead Asset Area - Eddy County, New Mexico +We turned to sales 16 gross (12.3 net) operated wells in the Arrowhead asset area during 2024. These wells, which included eight Wolfcamp A and eight Second Bone Spring completions, have produced in aggregate approximately 2.5 million BOE in approximately six months of production. These 16 wells had average completed lateral lengths of approximately 9,800 feet. +We also turned to sales 23 gross (1.7 net) non-operated wells in the Arrowhead asset area during 2024. +Rustler Breaks Asset Area - Eddy County, New Mexico +We turned to sales 32 gross (23.5 net) operated wells in the Rustler Breaks asset area during 2024. In total, these 32 Rustler Breaks wells, which included ten First Bone Spring, six Second Bone Spring, 12 Third Bone Spring Carbonate and four Wolfcamp B completions, have produced in aggregate approximately 5.7 million BOE in an average of approximately six months of production. These 32 wells had average completed lateral lengths of approximately 9,100 feet. +We also turned to sales 48 gross (3.2 net) non-operated wells in the Rustler Breaks asset area during 2024. +West Texas Asset Area - Loving, Ward and Winkler Counties, Texas +We turned to sales ten gross (0.2 net) non-operated wells in the West Texas asset area during 2024. +South Texas — Eagle Ford Shale and Other Formations +During the fourth quarter of 2024, we divested certain non-core assets in the Eagle Ford shale for approximately $11.5 million. At December 31, 2024, our remaining properties included approximately 2,900 gross (2,900 net) acres in the Eagle Ford shale play in South Texas. All of our Eagle Ford leasehold was held by existing production at December 31, 2024. +We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2024. In fact, as of December 31, 2024, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 8% to 986 BOE per day, including 719 Bbl of oil per day and 1.6 MMcf of natural gas per day, during 2024, as compared to 1,068 BOE per day, including 755 Bbl of oil per day and 1.9 MMcf of natural gas per day, during 2023. For each of the years ended December 31, 2024 and 2023, less than 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale. +At December 31, 2024, less than 1% of our estimated total proved oil and natural gas reserves, or 1.7 million BOE, was attributable to the Eagle Ford shale, including approximately 1.4 million Bbl of oil and 1.4 Bcf of natural gas. Our Eagle Ford total proved reserves comprised less than 1% of our proved oil reserves and less than 1% of our proved natural gas reserves at December 31, 2024, essentially unchanged from December 31, 2023. +Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations +We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that were turned to sales in 2024. +At December 31, 2024, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024. +For the year ended December 31, 2024, approximately 2% of our average daily oil equivalent production, or 3,492 BOE per day, including three Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2023, approximately 3% of our average daily oil equivalent production, or 4,025 BOE per day, including five Bbl of oil per day and 24.1 MMcf of natural gas per day, was attributable to +10 +Table of Contents +our properties in Northwest Louisiana. For the year ended December 31, 2024, approximately 5% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2023, approximately 7% of our daily natural gas production, or 24.1 MMcf of natural gas per day, was attributable to these properties. At December 31, 2024, less than 1% of our estimated total proved reserves, or 3.7 million BOE, was attributable to our properties in Northwest Louisiana. +Midstream Segment +Our midstream segment conducts midstream operations in support of, and provides flow assurance for, our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. +Southeast New Mexico and West Texas — Delaware Basin +On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the West Texas asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks asset area and in Loving County, Texas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and earned all of the potential $73.5 million in performance incentives through January 31, 2023. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement. +On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we earned $108.2 million in performance incentives through September 30, 2024. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements. +Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and the other midstream facilities that have been developed in the Greater Stebbins Area and the Stateline asset area. +On June 30, 2022, we acquired Pronto, including the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of gas gathering, water gathering and oil transportation and gathering pipeline assets. +On December 18, 2024, we completed the Pronto Transaction, pursuant to which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million. In connection with the Pronto Transaction, we received a special distribution from San Mateo of approximately $219.8 million. In addition, we have the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by us and 49% by Five Point. +Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. Pronto also owns and operates five compressor stations and approximately 120 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. +In connection with the Pronto Transaction, Matador dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and +11 +Table of Contents +processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind, an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing. +Natural Gas Gathering and Processing Assets +The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks. +In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2024, was also gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area. +At December 31, 2024, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2024, San Mateo was gathering or transporting almost all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area. +In addition, at December 31, 2024, San Mateo had NGL pipeline connections at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners L.P. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise. +In the Wolf portion of the West Texas asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the West Texas asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines. +At December 31, 2024, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2024, San Mateo gathered an average of approximately 426 MMcf of natural gas per day, an increase of 19% as compared to 358 MMcf of natural gas per day gathered during the year ended December 31, 2023. In addition, during the year ended December 31, 2024, San Mateo processed approximately 403 MMcf of natural gas per day at the Black River Processing Plant, an increase of 6%, as compared to 381 MMcf of natural gas per day processed during the year ended December 31, 2023. +Crude Oil Gathering and Transportation Assets +San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets. +At December 31, 2024, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the West Texas asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2024, we estimated almost all of our oil production from the Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area was transported by pipeline. +12 +Table of Contents +At December 31, 2024, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2024, the San Mateo Oil Pipeline Systems had throughput of approximately 52,600 Bbl of oil per day, an increase of 21%, as compared to throughput of approximately 43,600 Bbl of oil per day during the year ended December 31, 2023. +Produced Water Gathering and Disposal Assets +At December 31, 2024, San Mateo had four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area. At December 31, 2024, San Mateo had designed disposal capacity of approximately 475,000 Bbl of produced water per day. +During the year ended December 31, 2024, San Mateo handled approximately 462,400 Bbl of produced water per day, an increase of 23%, as compared to approximately 376,000 Bbl of produced water per day handled during the year ended December 31, 2023. +South Texas / Northwest Louisiana +In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo as of December 31, 2024. +Operating Summary +The following table sets forth certain unaudited production and operating data for the years ended December 31, 2024, 2023 and 2022. +Year Ended December 31, +2024 2023 2022 +Unaudited Production Data: +Net Production Volumes: +Oil (MBbl) 36,530 27,542 21,943 +Natural gas (Bcf) 155.8 123.4 99.3 +Total oil equivalent (MBOE) (1) +62,495 48,112 38,495 +Average daily production (BOE/d) (1) +170,751 131,813 105,465 +Average Sales Prices: +Oil, without realized derivatives (per Bbl) $ 75.89 $ 77.88 $ 96.32 +Oil, with realized derivatives (per Bbl) $ 75.89 $ 77.88 $ 92.87 +Natural gas, without realized derivatives (per Mcf) $ 2.38 $ 3.25 $ 7.98 +Natural gas, with realized derivatives (per Mcf) $ 2.47 $ 3.17 $ 7.15 +Operating Expenses (per BOE): +Production taxes, transportation and processing $ 4.91 $ 5.50 $ 7.33 +Lease operating $ 5.47 $ 5.06 $ 4.08 +Plant and other midstream services operating $ 2.74 $ 2.68 $ 2.48 +Depletion, depreciation and amortization $ 15.59 $ 14.90 $ 12.11 +General and administrative $ 2.04 $ 2.29 $ 3.02 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +13 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2024 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 36,265 263 — 2 36,530 +Natural gas (Bcf) 147.5 0.6 6.3 1.4 155.8 +Total oil equivalent (MBOE) (3) +60,856 361 1,046 232 62,495 +Percentage of total annual net production 97.4 % 0.6 % 1.7 % 0.3 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 99,086 719 — 3 99,808 +Natural gas (MMcf/d) 403.1 1.6 17.2 3.8 425.7 +Total oil equivalent (BOE/d) 166,273 986 2,859 633 170,751 +Average Sales Prices (4) +Oil (per Bbl) $ 75.90 $ 75.64 $ — $ 70.13 $ 75.89 +Natural gas (per Mcf) $ 2.40 $ 4.19 $ 1.95 $ 2.02 $ 2.38 +Total oil equivalent (per BOE) $ 51.05 $ 61.97 $ 11.67 $ 12.33 $ 50.31 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.87 $ 36.68 $ 6.10 $ 8.00 $ 6.23 +__________________ +(1) Includes 61 gross (41.0 net) wells from the Eagle Ford formation that were divested in 2024 and one well producing oil from the Austin Chalk formation in La Salle County, Texas that was divested in November 2024. +(2) Includes the Cotton Valley formation and shallower zones. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +14 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 27,264 276 — 2 27,542 +Natural gas (Bcf) 113.9 0.7 8.2 0.6 123.4 +Total oil equivalent (MBOE) (3) +46,253 390 1,373 96 48,112 +Percentage of total annual net production 96.1 % 0.8 % 2.9 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 74,697 755 — 5 75,457 +Natural gas (MMcf/d) 312.1 1.9 22.6 1.5 338.1 +Total oil equivalent (BOE/d) 126,720 1,068 3,761 264 131,813 +Average Sales Prices (4) +Oil (per Bbl) $ 77.90 $ 76.10 $ — $ 74.53 $ 77.88 +Natural gas (per Mcf) $ 3.32 $ 3.54 $ 2.23 $ 2.09 $ 3.25 +Total oil equivalent (per BOE) $ 54.10 $ 60.01 $ 13.39 $ 13.61 $ 52.91 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.99 $ 32.78 $ 4.59 $ 17.79 $ 6.19 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +15 +Table of Contents +The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. +Southeast +New Mexico/West Texas South Texas Northwest Louisiana +Delaware Basin +Eagle Ford (1) +Haynesville +Cotton Valley (2) +Total +Annual Net Production Volumes +Oil (MBbl) 21,585 355 — 3 21,943 +Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3 +Total oil equivalent (MBOE) (3) +36,550 501 1,383 61 38,495 +Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 % +Average Net Daily Production Volumes +Oil (Bbl/d) 59,139 971 — 9 60,119 +Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1 +Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465 +Average Sales Prices (4) +Oil (per Bbl) $ 96.34 $ 95.23 $ — $ 91.53 $ 96.32 +Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98 +Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48 +Production Costs (5) +Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43 +_________________ +(1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas. +(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. +(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Excludes impact of derivative settlements. +(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. +Our total oil equivalent production of approximately 62.5 million BOE for the year ended December 31, 2024 increased 30% from our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023. This increased production was primarily attributable to the Ameredev Acquisition and to our delineation and development operations in the Delaware Basin throughout 2024, which offset declining production in the Eagle Ford shale and Northwest Louisiana. Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, as compared to 131,813 BOE per day for the year ended December 31, 2023. Our average daily oil production for the year ended December 31, 2024 was 99,808 Bbl of oil per day, an increase of 32% from 75,457 Bbl of oil per day for the year ended December 31, 2023. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf of natural gas per day, an increase of 26% from 338.1 MMcf of natural gas per day for the year ended December 31, 2023. +Our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023 increased 25% from our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022. This increased production was primarily due to the Advance Acquisition and to our delineation and development operations in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, as compared to 105,465 BOE per day for the year ended December 31, 2022. Our average daily oil production for the year ended December 31, 2023 was 75,457 Bbl of oil per day, an increase of 26% from 60,119 Bbl of oil per day for the year ended December 31, 2022. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf of natural gas per day, an increase of 24% from 272.1 MMcf of natural gas per day for the year ended December 31, 2022. +16 +Table of Contents +Producing Wells +The following table sets forth information relating to producing wells at December 31, 2024. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 85% in all wells that we operated at December 31, 2024. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. +Oil Wells Natural Gas Wells Total Wells +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +1,769 927.4 180 92.4 1,949 1,019.8 +South Texas: +Eagle Ford 31 30.3 — — 31 30.3 +Northwest Louisiana: +Haynesville — — 268 18.5 268 18.5 +Cotton Valley (2) +— — 66 39.0 66 39.0 +Area Total — — 334 57.5 334 57.5 +Total 1,800 957.7 514 149.9 2,314 1,107.6 +__________________ +(1) Includes 226 gross (91.6 net) vertical wells that were primarily acquired in multiple transactions. +(2) Includes the Cotton Valley formation and shallower zones. +Estimated Proved Reserves +The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2024, 2023 and 2022. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +17 +Table of Contents +At December 31, (1) +2024 2023 2022 +Estimated Proved Reserves Data: (2) +Estimated proved reserves: +Oil (MBbl) 361,842 272,277 196,289 +Natural Gas (Bcf) 1,498.2 1,126.8 962.6 +Total (MBOE) (3) +611,536 460,070 356,722 +Estimated proved developed reserves: +Oil (MBbl) 206,269 161,642 116,030 +Natural Gas (Bcf) 963.2 782.7 632.9 +Total (MBOE) (3) +366,797 292,097 221,507 +Percent developed 60.0 % 63.5 % 62.1 % +Estimated proved undeveloped reserves: +Oil (MBbl) 155,573 110,635 80,259 +Natural gas (Bcf) 535.0 344.0 329.7 +Total (MBOE) (3) +244,740 167,973 135,215 +Standardized Measure (4) (in millions) +$ 7,376.6 $ 6,113.5 $ 6,983.2 +PV-10 (5) (in millions) +$ 9,233.8 $ 7,704.1 $ 9,132.2 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2024 were $71.96 per Bbl for oil and $2.13 per MMBtu for natural gas, for the 12 months ended December 31, 2023 were $74.70 per Bbl for oil and $2.64 per MMBtu for natural gas and for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. +(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(5) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2024, 2023 and 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2024, 2023 and 2022 were $1.86 billion, $1.59 billion and $2.15 billion, respectively. +Our estimated total proved oil and natural gas reserves increased 33% from 460.1 million BOE at December 31, 2023 to 611.5 million BOE at December 31, 2024. This increase in proved oil and natural gas reserves was primarily attributable to the Ameredev Acquisition and our delineation and development operations in the Delaware Basin during 2024. We increased our total proved oil and natural gas reserves by 119.9 million BOE as a result of acquisitions and trades during 2024. We also added 99.9 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2024, of which 28.4 million BOE resulted from new well locations turned to sales during 2024 to establish proved developed reserves and 71.5 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2024. These increases were partially offset by net downward revisions of prior estimates for proved oil and natural gas reserves, including the removal of 8.2 million BOE resulting from the 4% decrease in oil prices and the 19% decrease in natural gas prices used to estimate total proved reserves at December 31, 2024, as compared to December 31, 2023, and the removal of 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of the 15.3 million BOE to proved reserves at a future date. These downward revisions at December 31, 2024 were partially offset by positive forecast updates of 21.7 million BOE. +Our proved oil reserves grew 33% from approximately 272.3 million Bbl at December 31, 2023 to approximately 361.8 million Bbl at December 31, 2024. Our proved natural gas reserves increased 33% from 1.13 Tcf at December 31, 2023 to 1.50 Tcf at December 31, 2024. Our proved reserves to production ratio at December 31, 2024 was 9.8, an increase of 2% from 9.6 at December 31, 2023. +18 +Table of Contents +The Standardized Measure of our total proved oil and natural gas reserves increased 21% from $6.11 billion at December 31, 2023 to $7.38 billion at December 31, 2024. The PV-10 of our total proved oil and natural gas reserves increased 20% from $7.70 billion at December 31, 2023 to $9.23 billion at December 31, 2024. The increases in our Standardized Measure and PV-10 are primarily a result of the 33% increase in our total proved oil and natural gas reserves at December 31, 2024, as compared to December 31, 2023, partially offset by the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2024, as compared to December 31, 2023. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2024 were $71.96 per Bbl and $2.13 per MMBtu, a decrease of 4% and 19%, respectively, as compared to average oil and natural gas prices of $74.70 per Bbl and $2.64 per MMBtu used to estimate proved reserves at December 31, 2023. Our total proved reserves were made up of 59% oil and 41% natural gas at both December 31, 2024 and 2023. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table. +The following table summarizes changes in our estimated proved developed reserves at December 31, 2024. +Proved Developed Reserves +(MBOE) (1) +As of December 31, 2023 292,097 +Extensions and discoveries 28,376 +Net acquisitions of minerals-in-place 59,293 +Revisions of prior estimates (5,072) +Production (62,495) +Conversion of proved undeveloped to proved developed 54,598 +As of December 31, 2024 366,797 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +Our proved developed oil and natural gas reserves increased 26% from 292.1 million BOE at December 31, 2023 to 366.8 million BOE at December 31, 2024. We added 28.4 million BOE in proved developed reserves through extensions and discoveries during 2024, which resulted from new well locations drilled during 2024 to establish proved reserves. In addition, during 2024, we converted 54.6 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. We also increased our proved developed reserves by 59.3 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. Additionally, we realized approximately 5.1 million BOE in net downward revisions of prior estimates in 2024, most of which were attributable to the lower commodity prices used to estimate proved reserves at December 31, 2024, which resulted in shorter estimated economic lives for certain of our producing properties. These cumulative net increases of 137.2 million BOE to our proved developed reserves exceeded by 2.2 times our total oil and natural gas production of 62.5 million BOE in 2024. +Our proved developed oil reserves increased 28% from 161.6 million Bbl at December 31, 2023 to 206.3 million Bbl at December 31, 2024. Our proved developed natural gas reserves increased 23% from 782.7 Bcf at December 31, 2023 to 963.2 Bcf at December 31, 2024. Proved developed reserves constituted 60% of our total proved oil and natural gas reserves at December 31, 2024, as compared to 63% at December 31, 2023. +The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2024. +Proved Undeveloped Reserves +(MBOE) (1) +As of December 31, 2023 167,973 +Extensions and discoveries 71,534 +Net acquisitions of minerals-in-place 60,583 +Revisions of prior estimates (752) +Conversion of proved undeveloped to proved developed (54,598) +As of December 31, 2024 244,740 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +19 +Table of Contents +Our proved undeveloped oil and natural gas reserves increased 46% from 168.0 million BOE at December 31, 2023 to 244.7 million at December 31, 2024. We added 71.5 million BOE in proved undeveloped reserves through extensions and discoveries during 2024, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2024. In addition, we increased our proved undeveloped reserves by 60.6 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. These increases were partially offset by net downward revisions of prior estimates for proved oil and natural gas reserves, including the removal of 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin and the removal of 2.1 million BOE for certain expense and pricing updates. These downward revisions were largely offset by positive forecast updates of 16.2 million BOE. During 2024, we also converted 54.6 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. +At December 31, 2024, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2024 within five years of booking these reserves. The following table sets forth, since 2021, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). +Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves +Proved Undeveloped Reserves +Converted to +Proved Developed Reserves +Oil Natural Gas Total +(MBbl) (Bcf) +(MBOE) (1) +2021 23,965 96.6 40,071 $ 240,664 +2022 22,515 95.3 38,403 434,336 +2023 18,492 98.6 34,928 441,671 +2024 34,857 118.4 54,598 685,163 +Total 99,829 408.9 168,000 $ 1,801,834 +__________________ +(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +20 +Table of Contents +The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2024. +Net Proved Reserves (1) +Oil Natural Gas Oil Equivalent +Standardized Measure (2) +PV-10 (3) +(MBbl) (Bcf) +(MBOE) (4) +(in millions) (in millions) +Southeast New Mexico/West Texas: +Delaware Basin 360,396 1,474.8 606,196 $ 7,355.4 $ 9,207.3 +South Texas: +Eagle Ford 1,441 1.4 1,667 21.2 26.7 +Northwest Louisiana +Haynesville — 19.7 3,286 5.4 6.8 +Cotton Valley (5) +4 2.3 387 (5.6) (7.0) +Area Total 4 22.0 3,673 (0.2) (0.2) +Total 361,842 1,498.2 611,536 $ 7,376.6 $ 9,233.8 +__________________ +(1) Numbers in table may not total due to rounding. +(2) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. +(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2024 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2024 were approximately $1.86 billion. +(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. +(5) Includes the Cotton Valley formation and shallower zones. +Technology Used to Establish Reserves +Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods. +Internal Control Over Reserves Estimation Process +We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2024. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. +21 +Table of Contents +Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well. +Acreage Summary +The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2024. +Developed Acres Undeveloped Acres Total Acres +Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin 271,300 156,900 56,700 41,800 328,000 198,700 +South Texas: +Eagle Ford 2,900 2,900 — — 2,900 2,900 +Northwest Louisiana: +Haynesville 16,200 8,900 — — 16,200 8,900 +Cotton Valley 15,700 14,800 — — 15,700 14,800 +Area Total (1) +18,500 17,300 — — 18,500 17,300 +Total 292,700 177,100 56,700 41,800 349,400 218,900 +__________________ +(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana. +Undeveloped Acreage Expiration +The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2024 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2030 and beyond totals 2,400 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024. +Acres Acres Acres Acres Acres +Expiring 2025 Expiring 2026 Expiring 2027 Expiring 2028 Expiring 2029 +Gross Net Gross Net Gross Net Gross Net Gross Net +Southeast New Mexico/West Texas: +Delaware Basin (1) +12,700 7,500 14,800 8,000 16,700 14,100 5,200 5,200 4,600 4,600 +Total 12,700 7,500 14,800 8,000 16,700 14,100 5,200 5,200 4,600 4,600 +__________________ +(1) Approximately 56% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable. +Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect in most cases until the cessation of production in commercial quantities. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of such lease. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2024, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of +22 +Table of Contents +ten years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2024, approximately 3% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. +Drilling Results +The following table summarizes our drilling activity for the years ended December 31, 2024, 2023 and 2022 . +Year Ended December 31, +2024 2023 2022 +Gross Net Gross Net Gross Net +Development Wells +Productive 253 106.9 222 84.1 138 61.4 +Dry — — — — — — +Exploration Wells +Productive (1) +9 4.9 24 16.9 20 11.0 +Dry — — — — — — +Total Wells +Productive (2) +262 111.8 246 101.0 158 72.4 +Dry — — — — — — +(1) All of these wells are extension wells. +(2) Includes three gross (1.5 net) vertical wells in 2024, one gross (0.5 net) vertical well in 2023 and three gross (1.6 net) vertical wells in 2022. +At December 31, 2024, we had a total of 65 gross (45.5 net) development wells and ten gross (7.9 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations. +Marketing and Customers +Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also generally deducted from the price received for crude oil and liquids. +Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted NGLs based on either a negotiated percentage of the proceeds that are generated from the sale of NGLs or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. +The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel and energy sources; weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions or conflicts in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; the threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; tariffs and trade restrictions; and overall worldwide economic +23 +Table of Contents +conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled or unscheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” +The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” +For the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference. +Title to Properties +We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.” +We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. +Seasonality +Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” +24 +Table of Contents +Competition +The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. +Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. +Our ability to drill and explore for oil and natural gas, acquire properties and provide competitive midstream services will depend upon our ability to conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations. +The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.” +Environmental +Emissions Mitigation +We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines that we expect to have sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities. +Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control and Data Acquisition (“SCADA”) equipment at a number of our larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require. +Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions. +Water Management +Using improving technologies, where feasible, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations. +25 +Table of Contents +Land Stewardship +When feasible, we attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S. Department of Interior Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, dunes sagebrush lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations. +During 2024, 96% of our gross operated oil production and 99% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water. +Regulation +Oil and Natural Gas Regulation +Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. +Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing and setbacks, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. +Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. +Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions +26 +Table of Contents +having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. The NEPA evaluation process at the Department of the Interior has followed regulations issued by the Council on Environmental Quality (“CEQ”) for many years. However, recent court rulings, including a 2024 decision by the United States Court of Appeals for the District of Columbia, have held that CEQ lacks legal authority to issue binding regulations governing the NEPA process. In addition, following an executive order from the Trump administration, CEQ has announced that it is rescinding its NEPA regulations, and as a result, each government agency impacted by NEPA may be required to establish its own processes and procedures. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. +In January 2021, the Biden administration issued executive orders limiting and delaying the issuance of new leases and drilling permits on federal lands (the “Biden Administration Federal Lease Orders”). The pause in issuing new leases was challenged in court, and the BLM ultimately continued to issue leases during the Biden administration. Furthermore, in January 2025, the Trump administration revoked the executive order from President Biden pausing new oil and gas leases on public lands. +In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under NEPA in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. BLM later announced that drilling permit approvals could be considered for the subject leases, provided that the process included additional time for public comments and objections. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits, is uncertain. +In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the Environmental Protection Agency (the “EPA”) suggested increasing the value of the social cost of greenhouse gases from $51 per metric ton to $190 per metric ton, and in December 2023, the EPA used $190 per metric ton as the social cost of greenhouse gases in its final rule revising New Source Performance Standards (“NSPS”) and Emission Guidelines for greenhouse gas and volatile organic compound emissions in the oil and gas sector. As part of this final rulemaking, the EPA published a peer-reviewed report on the updated social cost of greenhouse gases estimates. However, in January 2025, the Trump administration revoked the Biden administration’s executive order regarding the social cost of greenhouse gases, withdrew the social cost of greenhouse gases estimates and directed the EPA administrator to consider issuing guidance eliminating the social cost of carbon calculation from any Federal permitting or regulatory decision. Future EPA rulemakings may reestablish the previous social cost of greenhouse gases estimates or incorporate new estimates developed in the future and potentially result in more stringent rules and regulations affecting the oil and gas sector. +In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In November 2023, the federal district court for the District of Columbia dismissed the case, holding that the environmental groups lacked standing. The environmental groups have appealed the district court’s ruling, and their appeal remains pending. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of +27 +Table of Contents +drilling permits, though the ultimate impact is uncertain given the Trump administration’s revocations of related executive orders. +In April 2024, the BLM finalized a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. Furthermore, following an executive order by the Trump administration, the Department of the Interior has announced it is evaluating whether to suspend, revise, or rescind the 2024 waste rule. The ultimate outcome of this process, including possible financial costs and any adverse impacts on our oil and natural gas operations, is uncertain. +Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed or been revoked, the impact of these and similar federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Pipeline Regulation +Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. As part of the Ameredev Acquisition, we acquired crude oil gathering and transportation pipelines with origin points from Lea County, New Mexico to various interconnections with third parties (the “Trophy Pipeline System”). The Trophy Pipeline System is also subject to FERC jurisdiction. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction. +In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims. +Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. +The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with +28 +Table of Contents +FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. +The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. +In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. +The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System and the Trophy Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. To enact the changes outlined in the notice of proposed rulemaking, PHMSA enacted three separate rules (together known as the “Mega Rule”). The first part of the Mega Rule was finalized in October 2019 and requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In September 2023, PHMSA issued a proposed rule applicable to gas transmission and distribution and gathering pipelines, which would require updates to emergency response plans and other safety practices. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.” +Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays. +U.S. Federal and State Taxation +The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico. +In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. +29 +Table of Contents +Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.” +Underground Injection and Hydraulic Fracturing +We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, have imposed additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. +We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” +The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible +30 +Table of Contents +linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” +Environmental, Health and Safety Regulation +The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us. +The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. +The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the EPA and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On January 18, 2023, the EPA and the Corps jointly issued a final rule revising the definition of WOTUS that largely returned to the pre-2015 regulatory regime. On September 8, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands only to those that have a continuous surface connection to water bodies. On August 29, 2023, the EPA and the Corps jointly issued a final rule, which took effect immediately, aligning the regulatory definition of WOTUS with the Supreme Court’s ruling. +CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of +31 +Table of Contents +hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA. +RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes. +The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which included a range of measures designed to address climate change, including the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. However, the Trump administration has announced a change in course. In January 2025, the Trump administration issued an executive order directing the U.S. Ambassador to the United Nations to immediately submit formal written notification of the U.S.’s withdrawal from the Paris Agreement and any agreement, pact, accord or similar commitment made under the United Nations Framework Convention on Climate Change, which would include the Glasgow Climate Pact. +In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibit flaring in certain circumstances and require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. In November 2024, the New Mexico Court of Appeals upheld the ozone precursor rule, though this decision may be appealed. +In January 2025, the NMED announced that, due to budget constraints, the NMED Cabinet Secretary will issue a temporary emergency rule to suspend deadlines to issue air permits. Air permits are required for the construction of new oil and gas production facilities or the modification of existing facilities in New Mexico. Whether this announcement will result in meaningful delays or cancelation of our permit applications is uncertain. Any interruption in our ability to timely obtain air permits could result in delays in or an inability to proceed with our development plans for our oil and natural gas operations. +32 +Table of Contents +Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. The Biden administration started a number of climate and environmental justice initiatives at the federal level. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort was designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA began implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. It is expected that policies relating to environmental matters will change under the Trump administration, but it is too soon to predict what the ultimate impact of the change in administration will be. +On March 8, 2024, the EPA issued a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources. Additionally, on November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. As another example, in April 2024, the EPA issued a final consent decree that established a December 10, 2024 deadline for the EPA to review and propose revisions to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. The EPA has not yet proposed any such revisions. +Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” +In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. +We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. +The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. On May 20, 2024, the USFWS issued a final rule listing the dunes sagebrush lizard as endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate and our ability to maximize production from our leases may be adversely impacted by these restrictions. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more +33 +Table of Contents +stringent environmental laws and regulations will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The overall trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable or unwilling to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” +Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. +We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance other than with respect to our midstream business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” +Office Location +Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. +Human Capital +At December 31, 2024, we had 452 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. +Employee Recruiting, Retention and Professional Development +Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders. +We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2024, for example, our employees completed approximately 22,500 hours of continuing education and study, equating to approximately 50 hours per employee. We also have a leadership program that fosters the development and growth of many of our staff with meetings and opportunities to enhance their leadership skills. +34 +Table of Contents +We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status. +Proactive Safety Culture +We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and our experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern. +We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. +Available Information +Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. +35 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/item13.txt b/raw/filings/0001520006/2024/0001520006-25-000066/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3faadf5f7ca13fb64608bd3c76b282a49028e0b1 --- /dev/null +++ b/raw/filings/0001520006/2024/0001520006-25-000066/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.” \ No newline at end of file diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/item9a.txt b/raw/filings/0001520006/2024/0001520006-25-000066/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..6ae0e6a34e2e3b5ab345b946d341d03afc47435f --- /dev/null +++ b/raw/filings/0001520006/2024/0001520006-25-000066/item9a.txt @@ -0,0 +1,32 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2024 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and +92 +Table of Contents +communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +Changes in Internal Control over Financial Reporting +During the quarter ended December 31, 2024, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. +Management’s Report on Internal Control over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. +KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2024 as included herein. +Important Considerations +The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +To the Shareholders and Board of Directors +Matador Resources Company: +Opinion on Internal Control Over Financial Reporting +We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2025 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ KPMG LLP +Dallas, Texas +February 25, 2025 +94 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/rp_note.txt b/raw/filings/0001520006/2024/0001520006-25-000066/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001520006/2024/0001520006-25-000066/rpt_disclosure.txt b/raw/filings/0001520006/2024/0001520006-25-000066/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e50131ad508527214558f598f5dd5654d7f0f658 --- /dev/null +++ b/raw/filings/0001520006/2024/0001520006-25-000066/rpt_disclosure.txt @@ -0,0 +1,152 @@ +TRANSACTIONS WITH RELATED PERSONS +TRANSACTIONS WITH RELATED PERSONS +Except as disclosed below, during 2024 , there was not, nor was there proposed as of December 31, 2024 , any transaction +or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds +$120,000 and in which any of our directors, nominees for directors, executive officers, beneficial owners of more than 5% +of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will +have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, +which are described in “Executive Compensation— Compensation Discussion and Analysis” and “Director Compensation” +above. +Working Interest and Overriding Royalty Interest Owners +Joseph Wm. Foran, Chairman and Chief Executive Officer, Shelley F. Appel, member of the Board, and certain of their +affiliated entities (collectively, the “Foran Entities”) are working interest owners and/or overriding royalty interest owners in +certain properties operated by the Company. As working interest owners, the Foran Entities are required to pay their +proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of +business. As overriding royalty interest owners, the Foran Entities are entitled to receive their proportionate share of +revenues from the wells in which they own an interest in the normal course of business. During 2024 , revenues, net of +costs, received by the Foran Entities in their capacity as working interest owners or overriding royalty interest owners were +approximately $17.2 million (the “Related Net Revenue Payments”). The Related Net Revenue Payments represent less +than 1% of our total third-party net revenue payments during 2024 . +In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective +working interests. During 2024 , our joint interest billings to the Foran Entities attributable to their share of costs were +approximately $13.7 million (the “Related Joint Interest Billings”). The Related Joint Interest Billings represent less than +1% of our total joint interest billings during 2024 . As a result of this ownership by the Foran Entities, from time to time, we +will be in a net receivable or net payable position with certain of the Foran Entities. We do not consider any net +receivables from the Foran Entities to be uncollectible. +The Audit Committee reviewed the terms of the working interests and/or overriding royalty interests of the Foran Entities +for potential conflicts of interest under the Company's Related Person Transaction Policy (the "Related Person +Transaction Policy"), and, after being fully informed as to Mr. Foran’s and Ms. Appel's relationships and interests in such +transactions and all other material facts related to the Related Net Revenue Payments and Related Joint Interest Billings, +determined that such transactions and the Related Net Revenue Payments and Related Joint Interest Billings were fair to +the Company and recommended such transactions and the Related Net Revenue Payments and Related Joint Interest +Billings to the full Board for approval and ratification. The Board subsequently approved and ratified the transactions and +the Related Net Revenue Payments and Related Joint Interest Billings. +Greyhound Joint Venture +The Company has entered into a joint venture, Greyhound, with Spearpoint Resources Company (“Spearpoint”) to +generate value through a well development program in our Twin Lakes asset area. An adult child of Mr. Foran and the +sibling of Ms. Appel is the founder of Spearpoint and serves as the chief executive officer and chairman of the board of +directors of Spearpoint. Mr. Foran’s child has a Bachelor of Arts degree in Economics from Princeton University, a Master +of Science degree in Petroleum Engineering from Texas A&M University and a Master of Business Administration degree +from Rice University. Mr. Foran’s child worked for a major oil and gas company as a petroleum petrophysicist. Prior to +attending Texas A&M, Mr. Foran’s child served in the United States Marine Corp, including two tours of duty overseas, and +has continued to serve in United States Marine Corp Reserve, recently achieving the rank of Major. Mr. Foran’s child may +perform shared services to Greyhound, for which Greyhound would reimburse Spearpoint. In addition, Ms. Appel holds an +ownership interest in Spearpoint. +During 2024 , the Company provided approximately $0.65 million of shared services to Greyhound and Spearpoint +provided approximately $0.30 million of shared services to Greyhound. Neither the Company nor Spearpoint made any +82 Matador Resources Company | 2025 Proxy Statement +capital contributions or received any distributions from Greyhound in 2024 , although such contributions and distributions +may be made or received by the Company and Spearpoint in the future. +The Audit Committee reviewed the terms of the joint venture for potential conflicts of interest under the Related Person +Transaction Policy, and, after being fully informed as to Mr. Foran’s, his adult child’s and Ms. Appel's relationships and +interests in such transactions and all other material facts related to Greyhound, determined that such transactions were +fair to the Company and recommended such transactions to the full Board for approval and ratification. The Board +subsequently approved and ratified the transactions. +Oilfield Equipment Purchase +The son-in-law of Mr. Foran and brother-in-law of Ms. Appel serves as the President of DCiii, LLC (“DC3”). During 2024, +the Company purchased certain oilfield equipment from DC3 for an aggregate amount of approximately $0.42 million (the +“Equipment Purchases”). The Audit Committee reviewed the terms of the Equipment Purchases for potential conflicts of +interest under the Related Person Transaction Policy and, after being fully informed as to Mr. Foran’s, his son-in-law’s and +Ms. Appel’s relationships and interests in such transactions and all other material facts related to the Equipment +Purchases, determined that the Equipment Purchases were fair to the Company and recommended the Equipment +Purchases to the full Board for approval and ratification. The Board subsequently approved and ratified the Equipment +Purchases. +Office Lease Renewal +R. Gaines Baty is a member of the Board. Mr. Baty’s son serves as the Vice Chairman and the Office Tenant +Representation Leader of Cushman & Wakefield’s Dallas-Fort Worth market. During 2024, Mr. Baty’s son provided tenant +representation services to the Company in connection with the Company’s renewal of its office lease for its Dallas, Texas +headquarters (the “Office Lease Renewal”). As a result of his services, Mr. Baty’s son is expected to have been +compensated in excess of $120,000. The Audit Committee reviewed the terms of the Office Lease Renewal for potential +conflicts of interest under the Related Person Transaction Policy and, after being fully informed as to Mr. Baty’s and his +son’s relationships and interests in such transactions and all other material facts related to the Office Lease Renewal, +determined that the Office Lease Renewal was fair to the Company and recommended the Office Lease Renewal to the +full Board for approval and ratification. The Board subsequently approved and ratified the Office Lease Renewal. +Certain Employment Relationships +Billy E. Goodwin served as an executive officer during 2024 until his retirement in April of 2024. During 2024 , an adult +child of Mr. Goodwin was an employee of the Company and has been an employee since 2015. In 2024, Mr. Goodwin’s +child was compensated between $120,000 and $750,000. Mr. Goodwin’s child has a Bachelor of Science in Business +Administration degree in Energy Management from the University of Tulsa and a Bachelor of Arts degree in General +Business and Management from Oklahoma State University. He has over 14 years of industry experience, including as a +drilling fluids engineer for a publicly traded oilfield services company and as a landman for a publicly traded exploration +and production company. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts +of interest under the Related Person Transaction Policy and, after being fully informed as to the employment arrangement +and compensation of Mr. Goodwin’s adult child, and all other material facts related to the relationship, determined that the +employment arrangement was fair to the Company and recommended the employment arrangement to the full Board for +approval and ratification. The Board subsequently approved and ratified such employment arrangements. +Reynald A. Baribault is a member of the Board. Mr. Baribault’s sister-in-law has been an employee of the Company since +2016 and was compensated in 2024 , and is expected to be compensated in 2025 , between $120,000 and $500,000. Mr. +Baribault’s sister-in-law has a diploma from the Executive Secretarial School and is a certified legal assistant, having +completed the Southern Methodist University Legal Assistants Program. She has over 40 years of experience as a legal +assistant. The Audit Committee reviewed the terms of the employment arrangement for potential conflicts of interest under +the Related Person Transaction Policy and, after being fully informed as to the employment arrangement and historical +and anticipated compensation of Mr. Baribault’s sister-in-law, and all other material facts related to the relationship, +determined that the employment arrangement was fair to the Company and recommended the employment arrangement +2025 Proxy Statement | Matador Resources Company 83 +to the full Board for approval and ratification. The Board subsequently approved and ratified such employment +arrangement. +An adult child of Mr. Foran and a sibling of Ms. Appel has been an employee of the Company since 2015 and was +compensated in 2024 , and is expected to be compensated in 2025 , between $120,000 and $500,000. Mr. Foran’s child +has a Bachelor of Science degree in Human Resource Development and a Master of Science degree in Human Resource +Management, both from Texas A&M University. She has more than 13 years of industry experience, including with another +publicly traded exploration and production company. The Audit Committee reviewed the terms of the employment +arrangement for potential conflicts of interest under the Related Person Transaction Policy and, after being fully informed +as to the employment arrangement and historical and anticipated compensation of Mr. Foran’s child, and all other material +facts related to the relationship, determined that the employment arrangement was fair to the Company and +recommended the employment arrangement to the full Board for approval and ratification. The Board subsequently +approved and ratified such employment arrangement. +Indemnification Agreements +We have entered into indemnification agreements with each of our directors and executive officers and expect to do so in +the future for any new directors and executive officers. The indemnification agreements provide the directors and +executive officers with contractual rights to indemnification, expense advancement and reimbursement to the fullest extent +permitted by applicable law. +Procedures for Approval of Related Person Transactions +Pursuant to the Related Person Transaction Policy in effect as of December 31, 2024 , a “Related Person Transaction” is +defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or +guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, in +which a Related Person (as defined below) has or will have a direct or indirect material interest and in which we are a +participant, other than: +• a transaction involving compensation of directors that is required to be reported in our proxy statement under Item 402 +of the SEC’s compensation disclosure requirements (“Item 402”); +• any employment by us of an executive officer if: +◦ the related compensation is required to be reported in our proxy statement under Item 402; or +◦ the executive officer is not an “immediate family member” of another executive officer or director of the +Company, the related compensation would be reported in our proxy statement under Item 402 if the executive +officer was a “named executive officer” and the Compensation Committee approved (or recommended that +the Board approve) such compensation; +• a transaction with a Related Person involving less than $120,000; +• a transaction in which the interest of the Related Person arises solely from the ownership of a class of our equity +securities and all holders of that class receive the same benefit on a pro rata basis; +• a transaction in which a Related Person has an indirect interest solely as a result of being (a) a director or, together +with all other Related Persons, a less than 10% beneficial owner of an equity interest in another entity, or both, or (b) a +limited partner in a partnership in which the Related Person, together with all other Related Persons, has an interest of +less than 10%; +• a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that +involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in +conformity with law or governmental authority; +84 Matador Resources Company | 2025 Proxy Statement +• any transaction with another company at which a Related Person’s only relationship is as an employee (other than an +executive officer), if the aggregate amount involved does not exceed the greater of $1,000,000, or 2% of that +company’s total annual revenues; +• any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a +Related Person’s only relationship is as an employee (other than an executive officer), if the aggregate amount +involved does not exceed the lesser of $1,000,000, or 2% of the charitable organization’s total annual receipts; +• any transaction with another publicly traded company where the Related Person’s interest arises solely from beneficial +ownership of more than 5% of our Common Stock and ownership of a non-controlling interest in the other publicly +traded company; +• reimbursement of business expenses incurred by a director, officer or employee of the Company in the performance of +his or her duties and approved for reimbursement by the Company in accordance with the Company’s customary +policies and practices; or +• indemnification and advancement of expenses made pursuant to the Certificate of Formation or the Bylaws or +pursuant to any agreement. +“Related Person” means: +• any person who is, or at any time since the beginning of the Company’s last completed fiscal year was, one of our \ No newline at end of file